10-K 1 km-form10k_feb2008.htm FORM 10-K


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 


Form 10-K

 

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the fiscal year ended December 31, 2007

 

 

 

Or

 

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the transition period from          to

Commission file number: 1-11234

Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)

 

 

Delaware

76-0380342

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

500 Dallas, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)

Registrant’s telephone number, including area code: 713-369-9000

 


Securities registered pursuant to Section 12(b) of the Act:

 

 

 

Title of each class

 

Name of each exchange on which registered


 


Common Units

 

New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:
None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes x  No 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

1




          Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes 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 29, 2007 was approximately $8,185,538,074. As of January 31, 2008, the registrant had 170,224,734 Common Units outstanding.

2



KINDER MORGAN ENERGY PARTNERS, L.P.

 

 

          TABLE OF CONTENTS

 


 

 

 

 

 

 

 

 

 

Page
Number

 

 

 

 


 

 

 

 

 

PART I

 

Items 1 and 2.

Business and Properties

4

General Development of Business

4

Organizational Structure

4

Recent Developments

5

Financial Information about Segments

10

Narrative Description of Business

10

Business Strategy

10

Business Segments

10

Products Pipelines

11

Natural Gas Pipelines

16

CO2

24

Terminals

29

Trans Mountain

30

Major Customers

31

Regulation

31

Environmental Matters

34

Other

36

Financial Information about Geographic Areas

36

Available Information

36

Item 1A.

Risk Factors

37

Item 1B.

Unresolved Staff Comments

46

Item 3.

Legal Proceedings

46

Item 4.

Submission of Matters to a Vote of Security Holders

46

 

 

 

 

 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities

47

Item 6.

Selected Financial Data

48

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

50

Critical Accounting Policies and Estimates

51

Results of Operations

53

Liquidity and Capital Resources

68

Recent Accounting Pronouncements

77

Information Regarding Forward-Looking Statements

77

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

79

Energy Commodity Market Risk

79

Interest Rate Risk

81

Item 8.

Financial Statements and Supplementary Data

82

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

82

Item 9A.

Controls and Procedures

83

Item 9B.

Other Information

83

 

 

 

 

 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

84

Directors and Executive Officers of our General Partner and its Delegate

84

Corporate Governance

86

Section 16(a) Beneficial Ownership Reporting Compliance

87

Item 11.

Executive Compensation

88

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters

103

Item 13.

Certain Relationships and Related Transactions, and Director Independence

105

Item 14.

Principal Accounting Fees and Services

109

 

 

 

 

 

PART IV

 

Item 15.

Exhibits and Financial Statement Schedules

110

Index to Financial Statements

114

Signatures

211

3



PART I

Items 1 and 2. Business and Properties.

          In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., a Delaware limited partnership 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 25,000 miles of pipelines and approximately 165 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 approximately $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. 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) American International Group, Inc.; (iii) The Carlyle Group; and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as the “going-private transaction.”

          As of December 31, 2007, Knight and its consolidated subsidiaries owned, through its general and limited partner interests, an approximately 13.9% 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. This incentive distribution is calculated in increments based on the amount by which quarterly distributions to our unitholders exceed specified target levels as set forth in our partnership agreement, reaching a maximum of 50% of distributions allocated to the general partner for distributions above $0.23375 per limited partner unit per quarter. Including both its general and limited partner interests in us, at the 2007 distribution level, Knight received approximately 49% of all quarterly “Available Cash” distributions (as defined in our partnership agreement) from us, with approximately 43% and 6% of all quarterly distributions from us attributable to Knight’s general partner and limited partner interests, respectively. 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.

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          Kinder Morgan Management, LLC, referred to as “KMR” in this report, is a Delaware limited liability company formed in February 2001. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, our general partner has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries.

          KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.” Since its inception, KMR has used substantially all of the net proceeds received from the public offerings of its shares to purchase i-units from us. The i-units are a separate class of limited partner interests in us and are issued only to KMR. Under the terms of our partnership agreement, the holders of our i-units are entitled to vote on all matters on which the holders of our common units are entitled to vote.

          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, 2007, KMR, through its ownership of our i-units, owned approximately 29.2% of all of our outstanding limited partner units.

          Recent Developments

          The following is a brief listing of significant developments since December 31, 2006. Additional information regarding most of these items may be found elsewhere in this report.

 

 

 

 

Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own from affiliates of BP 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;

 

 

 

 

On January 17, 2007, we announced that our CO2 business segment will invest approximately $120 million to further expand its operations and enable it to meet the increased demand for carbon dioxide in the Permian Basin. The expansion activities will take place in southwest Colorado and include developing a new carbon dioxide source field (named the Doe Canyon Deep Unit that went in service during the first quarter of 2008) and adding infrastructure at both the McElmo Dome Unit and the Cortez Pipeline. The entire expansion is expected to be completed by the middle of 2008;

 

 

 

 

On January 30, 2007, we completed a public offering of senior notes. We issued a total of $1.0 billion in principal amount of senior notes, consisting of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50% notes due February 1, 2037. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $992.8 million, and we used the proceeds to reduce the borrowings under our commercial paper program;

 

 

 

 

On February 14, 2007, the first phase of the Rockies Express pipeline system, the 327-mile REX-Entrega Project, was placed in service at a cost of approximately $745 million and provided up to 500 million cubic feet of natural gas capacity from the Meeker Hub in Rio Blanco County, Colorado and Wamsutter Hub in Sweetwater County, Wyoming to the Cheyenne Hub in Weld County, Colorado.

 

 

 

 

 

The Rockies Express pipeline project is an approximate $4.9 billion, 1,679-mile natural gas pipeline system which is owned and currently being developed by Rockies Express Pipeline LLC. The Rockies Express

 

5



 

 

 

 

 

pipeline project is to be completed in three phases: (i) a 327-mile, $745 million pipeline running from the Meeker Hub to the Cheyenne Hub with a nominal capacity of 500 million cubic feet per day; (ii) a 713-mile, $1.6 billion pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri, transporting up to 1.5 billion cubic feet per day; and (iii) a 639-mile, $2.6 billion pipeline from Audrain County, Missouri to Clarington, located in Monroe County, Ohio. When fully completed, the Rockies Express pipeline system 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 January 12, 2008, interim service on the REX-West Project (second phase) commenced. Full service on the REX-West system for 1.5 billion cubic feet per day of contracted capacity is expected to commence in mid-March 2008. See “—(c) Narrative Description of Business—Business Segments—Natural Gas Pipelines—Rockies Express Pipeline” for more information;


 

 

 

 

On February 28, 2007, we announced plans to invest up to $100 million to expand our liquids terminal facilities in order to help serve the growing biodiesel market. We entered into long-term agreements as lessors with Green Earth Fuels, LLC to build tankage that will handle biodiesel at our Houston Ship Channel liquids facility. Green Earth Fuels completed construction of an 86 million gallon biodiesel production facility at our Galena Park, Texas liquids terminal in the fourth quarter of 2007;

 

 

 

 

On April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for $549.1 million. 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, currently transports approximately 260,000 barrels per day. An additional expansion that will increase capacity of the pipeline to 300,000 barrels per day is expected to be in service by November 2008. Current accounting principles require our consolidated financial statements and all other financial information included in this report to be stated to assume that the transfer of Trans Mountain net assets from Knight to us had occurred at the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006). As a result, financial statements and financial information presented for prior periods in this report have been restated to reflect our acquisition. In addition, due to the fact that 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 have identified our Trans Mountain pipeline system as a separate reportable business segment. For additional information regarding this acquisition, see Note 3 to our consolidated financial statements;

 

 

 

 

On May 14, 2007, we announced plans to construct a $72 million natural gas pipeline designed to bring new supplies out of East Texas to markets in the Houston and Beaumont, Texas areas. The new pipeline will consist of approximately 63 miles of 24-inch diameter pipe and multiple interconnections with other pipelines. It will connect our Kinder Morgan Tejas system in Harris County, Texas to our Kinder Morgan Texas Pipeline system in Polk County near Goodrich, Texas. In addition, we entered into a long-term binding agreement with CenterPoint Energy Services, Inc. to provide firm transportation for a significant portion of the initial project capacity, which will consist of approximately 225 million cubic feet per day of natural gas using existing compression and be expandable to over 400 million cubic feet per day with additional compression;

 

 

 

 

On May 17, 2007, KMR closed the public offering of 5,700,000 of its shares 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. We used the proceeds of $297.9 million from our i-unit issuance to reduce the borrowings under our commercial paper program;

 

 

 

 

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 $57.2 million, consisting of $38.8 million in cash and $18.4 million in assumed liabilities. The Vancouver Wharves facility is located on the north shore of the Port of Vancouver’s main harbor, and includes five deep-sea vessel berths situated on a 139-acre site. The terminal assets include significant 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;

6



 

 

 

 

On June 21, 2007, we closed a public offering of $550 million in principal amount of 6.95% senior notes. The notes are due January 15, 2038. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $543.9 million, and we used the proceeds to reduce our commercial paper debt;

 

 

 

 

On June 22, 2007, the Federal Energy Regulatory Commission, referred to in this report as the FERC, issued an order granting construction and operation of our Kinder Morgan Louisiana Pipeline project, and we officially accepted the order on July 10, 2007. The Kinder Morgan Louisiana Pipeline is expected to cost approximately $510 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, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including Natural Gas Pipeline Company of America. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total and is expected to be in service by January 1, 2009;

 

 

 

 

On July 10, 2007, we announced a combined $41 million investment for two terminal expansions to help meet the growing need for terminal services in key markets along the Gulf Coast. The investment consists of (i) the construction of a terminal that will include liquids storage, transfer and packaging facilities at the Rubicon Plant site in Geismar, Louisiana; and (ii) the purchase of liquids storage tanks from Royal Vopak in Westwego, Louisiana. The tanks have a storage capacity of approximately 750,000 barrels for vegetable oil, biodiesel, ethanol and other liquids products. The new terminal being built in Geismar will be capable of handling inbound and outbound material via pipeline, rail, truck and barge/vessel. Construction is expected to be complete by the fourth quarter of 2008;

 

 

 

 

On July 23, 2007, following the FERC’s expedited approval of our CALNEV Pipeline’s proposed tariff rate structure, we announced our continuing development of the approximate $426 million expansion of the pipeline system into Las Vegas, Nevada. The expansion involves the construction of a new 16-inch diameter pipeline, which will parallel existing utility corridors between Colton, California and Las Vegas in order to minimize environmental impacts. System capacity would increase to approximately 200,000 barrels per day upon completion of the expansion, and could be increased as necessary to over 300,000 barrels per day with the addition of pump stations. The CALNEV expansion is expected to be complete in early 2011;

 

 

 

 

On August 6, 2007, Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, filed for regulatory approval to construct and operate a 41-mile, $29 million natural gas pipeline from the Cheyenne Hub to markets in and around Greeley, Colorado. When completed, the Colorado Lateral expansion project will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. On February 21, 2008, the FERC granted the certification application;

 

 

 

 

On August 23, 2007, we announced that we have begun construction on the approximately C$467 million  Anchor Loop project, the second phase of the Trans Mountain pipeline system expansion that will increase pipeline capacity from approximately 260,000 to 300,000 barrels of crude oil per day. The project is expected to be complete in November 2008. In April 2007, we commissioned 10 new pump stations which boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day. The pipeline is currently operating at full capacity;

 

 

 

 

On August 28, 2007, we closed a public offering of $500 million in principal amount of 5.85% senior notes. The notes are due September 15, 2012. We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $497.8 million, and we used the proceeds to reduce our commercial paper debt;

 

 

 

 

Effective September 1, 2007, we acquired five bulk terminal facilities from Marine Terminals, Inc. for an aggregate consideration of approximately $101.5 million, consisting of $100.3 million in cash and an assumed liability of $1.2 million. The acquired assets and operations are primarily involved in the handling and storage of steel and alloys, and also provide stevedoring and harbor services, scrap handling, and scrap processing services to customers in the steel and alloys industry. The operations are located in Blytheville, Arkansas; Decatur, Alabama; Hertford, North Carolina; and Berkley, South Carolina. Combined, the five

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facilities handled approximately 13.7 million tons of steel products in 2007. Under long-term contracts, the acquired terminal facilities will continue to provide handling, processing, harboring and warehousing services to Nucor Corporation, one of the nation’s largest steel and steel products companies;


 

 

 

 

Effective October 5, 2007, we sold our North System natural gas liquids and refined petroleum products pipeline system and our 50% ownership interest in the Heartland Pipeline Company 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 on the sale of these net assets. In accordance with generally accepted accounting principles, we accounted for the North System business as a discontinued operation for all periods presented in this report, and we reported the gain with the caption as “Gain on disposal of North System” on our accompanying consolidated statement of income;

 

 

 

 

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 own a 50% interest in Midcontinent Express Pipeline LLC and Energy Transfer Partners L.P. owns the remaining 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 total project is expected to cost approximately $1.3 billion, and will have an initial transportation capacity of approximately 1.4 billion cubic feet per day of natural gas.


 

 

 

 

 

The Midcontinent Express Pipeline will originate near Bennington, Oklahoma and terminate at an interconnect with Williams’ Transco natural gas pipeline system near Butler, Alabama. It will also connect to Natural Gas Pipeline Company of America’s natural gas pipeline and to Energy Transfer Partners’ 135-mile natural gas pipeline, which extends from the Barnett Shale natural gas producing area in North Texas to an interconnect with the Texoma Pipeline near Paris, Texas. The Midcontinent Express Pipeline now has long-term binding commitments from multiple shippers for approximately 1.2 billion cubic feet per day and, in order to provide a seamless transportation path from various locations in Oklahoma, the pipeline has also executed a firm capacity lease agreement with Enogex, Inc., an Oklahoma-based intrastate natural gas gathering and pipeline company that is wholly-owned by OGE Energy Corp. Subject to the receipt of regulatory approvals, construction of the pipeline is expected to commence in August 2008 and be in service during the first quarter of 2009.

 

 

 

 

 

In January 2008, in conjunction with the signing of additional binding transportation commitments, Midcontinent Express and MarkWest 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%;

 

 

 


 

 

 

 

On October 17, 2007, we announced that we will invest approximately $23 million to expand our Kinder Morgan Interstate Gas Transmission pipeline system in order to serve five separate industrial plants (four of which produce ethanol) near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts, and subject to the receipt of regulatory approvals filed December 21, 2007, the expansion project is expected to be fully operational by the fall of 2008. Since 2000, our KMIGT system has connected to 17 new ethanol plants, 11 of which are located in the state of Nebraska;

 

 

 

 

On November 26, 2007, we announced that we expect to declare cash distributions of $4.02 per unit for 2008, an almost 16% increase over our cash distributions of $3.48 per unit for 2007. This expectation includes contributions from assets owned by us as of the announcement date and does not include any potential benefits from unidentified acquisitions. Additionally, our expectation does not take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’

8



 

 

 

 

 

interstate pipelines. Our expected growth in distributions in 2008 will be fueled by incremental earnings from Rockies Express-West (the western portion of the Rockies Express Pipeline), higher hedge prices on our

 

 

 

 

 

crude oil production (budgeted production volumes for the SACROC oil field unit in 2008 are approximately equal to the volumes realized in 2007), and an anticipated strong performance from our remaining business portfolio;


 

 

 

 

In December 2007, we completed a public offering of 7,130,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 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, and we used the proceeds to reduce the borrowings under our commercial paper program;

 

 

 

 

In December 2007, we completed a second expansion of our Pacific operations’ East Line pipeline segment. This expansion consisted of replacing approximately 130 miles of 12-inch diameter pipe between El Paso, Texas and Tucson, Arizona with new 16-inch diameter pipe, constructing additional pump stations, and adding new storage tanks at Tucson. The project, completed at a cost of approximately $154 million, will increase East Line capacity by 36% (to approximately 200,000 barrels per day) to meet the demand for refined petroleum products, and will provide the platform for further incremental expansions through horsepower additions to the system;

 

 

 

 

On December 31, 2007, TransColorado Gas Transmission LLC completed an approximate $50 million expansion to provide up to 250 million cubic feet per day of natural gas transportation, starting January 1, 2008, from the Blanco Hub to an interconnect with the Rockies Express pipeline system at the Meeker Hub;

 

 

 

 

During 2007, we spent $1,691.6 million for additions to our property, plant and equipment, including both expansion and maintenance projects. Our capital expenditures included the following:


 

 

 

 

 

 

$480.0 million in our Terminals segment, largely related to expanding the petroleum products storage capacity at our liquids terminal facilities, including the construction of additional liquids storage tanks at our facilities in Canada and at our facilities located on the Houston Ship Channel and the New York Harbor, and to various expansion projects and improvements undertaken at multiple terminal facilities;

 

 

 

 

 

 

$382.5 million in our CO2 segment, mostly related to additional infrastructure, including wells and injection and compression facilities, to support the expanding carbon dioxide flooding operations at the SACROC and Yates oil field units in West Texas and to expand our capacity to produce and deliver CO2 from our McElmo Dome and Doe Canyon Source Fields;

 

 

 

 

 

 

$305.7 million in our Trans Mountain segment, mostly related to pipeline expansion and improvement projects undertaken to increase crude oil and refined products delivery volumes;

 

 

 

 

 

 

$264.0 million in our Natural Gas Pipelines segment, mostly related to current construction of our Kinder Morgan Louisiana Pipeline and to various expansion and improvement projects on our Texas intrastate natural gas pipeline systems, including the development of additional natural gas storage capacity at our natural gas storage facilities located at Markham and Dayton, Texas; and

 

 

 

 

 

 

$259.4 million in our Products Pipelines segment, mostly related to the continued expansion work on our Pacific operations’ East Line products pipeline, completion of construction projects resulting in additional capacity, and an additional refined products line on our CALNEV Pipeline in order to increase delivery service to the growing Las Vegas, Nevada market;

 

 

 

 

 

 

Our capital expansion program in 2007 was approximately $2.6 billion (including our share of capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects). Including all of our business acquisition expenditures, total spending was $3.3 billion. Our capital expansion program will continue to be significant in 2008, as we expect to invest approximately $3.3 billion in expansion capital expenditures (including our share of capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects), which will help drive earnings and cash flow growth in 2009 and beyond;

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On January 16, 2008, we announced that we plan 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 February 12, 2008, we completed an additional 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 received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program; and

 

 

 

 

On February 12, 2008, we completed an additional 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.

           (b) Financial Information about Segments

          For financial information on our five reportable business segments, see Note 15 to our consolidated financial statements.

           (c) Narrative Description of Business

           Business Strategy

          The objective of our business strategy is to grow our portfolio of businesses by:

 

 

 

 

focusing on stable, fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets within 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.

          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 14,700 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

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CO2— 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 108 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

 

 

 

 

Trans Mountain—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.

          Generally, as utilization of our pipelines and terminals increases, our fee-based revenues increase. We do not face significant risks relating directly to short-term movements in commodity prices for two principal reasons. First, we primarily transport and/or handle products for a fee and are not engaged in significant unmatched purchases and resales of commodity products. Second, in those areas of our business where we do face exposure to fluctuations in commodity prices, primarily oil production in our CO2 business segment, we engage in a hedging program to mitigate this exposure.

          We regularly consider and enter into discussions regarding potential acquisitions, including those from 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.

          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.

          Products Pipelines

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

          Pacific Operations

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

          Our Pacific operations serve seven western states with approximately 3,000 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to some of the fastest growing population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. For 2007, the three main product types transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).

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

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          Our Pacific operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage capacity of approximately 13.7 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and oxygenate blending.

          Our Pacific operation’s West Coast Liquid 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 8.3 million barrels of storage for both petroleum products and chemicals.

          Markets. Combined, our Pacific 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 14 military bases. Currently, our Pacific 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 depends on such factors as prevailing economic conditions, vehicular use patterns and demographic changes in the markets served. If current trends continue, we expect the majority of our Pacific operations’ markets to maintain growth rates that will exceed the national average for the foreseeable future. The volume of products transported is affected by various factors, principally demographic growth, economic conditions, product pricing, vehicle miles traveled, population and fleet mileage. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year.

          Supply. The majority of refined products supplied to our Pacific operations’ pipeline system come from the major refining centers around Los Angeles, San Francisco, El Paso and Puget Sound, as well as from waterborne terminals and connecting pipelines located near these refining centers.

          Competition. The two most significant competitors of our Pacific 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 Pacific operations will be built in the foreseeable future. However, the possibility of individual pipelines being constructed or expanded to serve specific markets is a continuing competitive factor.

          The use of trucks for product distribution from either shipper-owned proprietary terminals or from their refining centers continues to compete for short haul movements by pipeline. Our Pacific 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 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 2007, Plantation delivered an average of 535,672 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (63%), diesel/heating oil (23%) and jet fuel (14%). Average delivery volumes for 2007 were 3.5% lower than the 555,063 barrels per day delivered during 2006. The decrease was predominantly driven by (i) the full year impact of alternative pipeline service (initial startup mid-2006) into Southeast markets, and (ii) changes in production patterns from Louisiana refineries related to refiners directing

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higher margin products (such as reformulated gasoline blendstock for oxygenate blending) into markets not directly served by Plantation.

          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 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 increased 3% in 2007 compared to 2006, with the majority of this growth 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 a 110-mile, 16-inch diameter pipeline that transports gasoline and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an intermediate delivery point on the 10-inch pipeline at Intercession City, Florida. In addition to being connected to our Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Petroleum. The 10-inch diameter pipeline is connected to our Taft, Florida terminal (located near Orlando) and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2007, the pipeline system transported approximately 113,800 barrels per day of refined products, with the product mix being approximately 69% gasoline, 12% diesel fuel, and 19% jet fuel.

          We also 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, diesel fuel and jet fuel for further movement into either trucks or into the Central Florida pipeline system. The Tampa terminal also provides storage and truck rack blending services for ethanol and bio-diesel. The Taft terminal contains approximately 0.7 million barrels of storage capacity, for gasoline 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

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

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

          With respect to the terminal operations at Tampa, the most significant competitors are proprietary terminals owned and operated by major oil companies, such as Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and the 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 2007, the pipeline system transported approximately 40,600 barrels per day of natural gas liquids.

          Markets. The pipeline traverses three provinces in Canada and seven states in the United States transporting high vapor pressure ethane, propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. 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,

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Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for natural gas liquids gathering, transportation, fractionation and storage in the United States.

          Markets. The pipeline was built to service Westlake Petrochemicals Corporation in the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in 2011. The contract requires a minimum volume of 30,000 barrels per day.

          Supply. The Cypress pipeline originates in Mont Belvieu where it is able to receive ethane and ethane/propane mix from local storage facilities. Mont Belvieu has facilities to fractionate natural gas liquids received from several pipelines into ethane and other components. Additionally, pipeline systems that transport natural gas liquids from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to Mont Belvieu.

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

          Southeast Terminals

          Our Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this report as KMST, was formed 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 361,000 barrels of refined products per day during 2007 and approximately 347,000 barrels of refined products per day during 2006.

          Markets. KMST’s acquisition and marketing activities are focused on the Southeastern United States from Mississippi through Virginia, including Tennessee. The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks. KMST also offered ethanol blending and storage services in northern Virginia during 2007. 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/or Colonial pipelines. To the maximum extent practicable, we endeavor to connect KMST terminals to both Plantation and Colonial.

          Competition. There are relatively few independent terminal operators in the Southeast. Most of the refined petroleum products terminals in this region are owned by large oil companies (BP, Motiva, Citgo, Marathon, and Chevron) who use these assets to support their own proprietary market demands as well as product exchange activity. These oil companies are not generally seeking third party throughput customers. Magellan Midstream Partners and TransMontaigne Product Services represent the other 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 2007 and approximately 9.1 million barrels in 2006.

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          In 2007, we increased the processing capacity of the recently constructed Greensboro, North Carolina transmix facility to better serve the needs of Plantation. The facility, which is located within KMST’s refined products tank farm, now has the capability to process approximately 8,500 barrels of transmix per day. In addition to providing additional processing business, the facility continues to provide Plantation a lower cost alternative compared to other transmix processing arrangements that recover ultra low sulfur diesel, and also more fully utilizes current KMST tankage at the Greensboro, North Carolina tank farm.

          Markets. The Gulf and East Coast refined petroleum products distribution system, particularly the Mid-Atlantic region, is the target market for our East Coast transmix processing operations. The Mid-Continent area and the New York Harbor are the target markets for our Illinois and Pennsylvania assets, respectively. Our West Coast transmix processing operations support the markets served by our Pacific operations in Southern California.

          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 14,700 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. Our transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets.

          Texas Intrastate Natural Gas Pipeline Group

          The group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems:

 

 

 

 

our Kinder Morgan Texas Pipeline;

 

 

 

 

our Kinder Morgan Tejas Pipeline;

 

 

 

 

our Mier-Monterrey Mexico Pipeline; and

 

 

 

 

our Kinder Morgan North Texas Pipeline.

          The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a single pipeline system, providing customers and suppliers with improved flexibility and reliability. The combined system includes approximately 6,000 miles of intrastate natural gas pipelines with a peak transport and sales capacity of approximately 5.2 billion cubic feet per day of natural gas and approximately 120 billion cubic feet of system natural gas storage capacity. In addition, the combined system, through owned assets and contractual arrangements with third parties, has the capability to process 915 million cubic feet per day of natural gas for liquids extraction and to treat approximately 250 million cubic feet per day of natural gas for carbon dioxide removal.

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          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 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 owns and operates an approximately 97-mile, 24-inch diameter pipeline that extends from a point of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica at the International Border between the United States and Mexico, to a point of interconnection with other intrastate pipeline facilities of Kinder Morgan Tejas located at King Ranch, Kleburg County, Texas. The 97-mile pipeline, referred to as the import/export facility, is capable of importing Mexican gas into the United States, and exporting domestic gas to Mexico. The imported Mexican gas is received from, and the exported domestic gas is delivered to, Pemex. The capacity of the import/export facility is approximately 300 million cubic feet of natural gas per day.

          Our Mier-Monterrey Pipeline consists of a 95-mile, 30-inch diameter natural gas pipeline that stretches from south Texas to Monterrey, Mexico and can transport up to 375 million cubic feet per day. The pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX natural gas transportation system. We have entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.

          Our Kinder Morgan North Texas Pipeline consists of an 86-mile, 30-inch diameter pipeline that transports natural gas from an interconnect with the facilities of Natural Gas Pipeline Company of America LLC, 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. In 2006, the existing system was enhanced to be bi-directional, so that deliveries of additional supply coming out of the Barnett Shale area can be delivered into NGPL’s pipeline as well as power plants in the area.

          We also own and operate various gathering systems in South and East Texas. These systems aggregate natural gas supplies into our main transmission pipelines, and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. We own plants that can process up to 115 million cubic feet per day of natural gas for liquids extraction. In addition, we have contractual rights to process approximately 800 million cubic feet per day of natural gas at various third-party owned facilities. We also own and operate three natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of natural gas for carbon dioxide removal at our Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at our Thompsonville Facility located in Jim Hogg County, Texas.

          Our North Dayton natural gas storage facility, located in Liberty County, Texas, has two existing storage caverns providing approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of cushion gas. We have entered into a long-term storage capacity and transportation agreement with NRG 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, Coral Energy Resources, L.P. operates the facility and controls the 96 billion cubic feet of natural gas working capacity, and we provide transportation service into and out of the facility.

          Additionally, we lease a salt dome storage facility located near Markham, Texas according to the provisions of an operating lease that expires in March 2013. We can, at our sole option, extend the term of this lease for two

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additional ten-year periods. The facility was expanded in 2007 and now consists of four salt dome caverns with approximately 17.3 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 BP America Production Company in Brazoria County, Texas. The Stratton Ridge Facilities have a combined working natural gas capacity of 1.4 billion cubic feet and a peak day deliverability of 100 million cubic feet per day. A lease with Dow Hydrocarbon & Resources, Inc. for a salt dome cavern containing approximately 5.0 billion cubic feet of working capacity expired during the third quarter of 2007.

          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. Additionally, in 2007, we have increased our capability and commitment to serve the growing local natural gas distribution market in the greater Houston metropolitan area.

          We serve the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and our Mier-Monterrey Mexico pipeline. In 2007, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 206 million cubic feet per day of natural gas, and there were several days of exports to the United States which ranged up to 250 million cubic feet per day. Deliveries to Monterrey also generally ranged from zero to 312 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 is well positioned to interconnect with liquefied natural gas projects currently under development by others along the Texas Gulf Coast.

          Competition. The Texas intrastate natural gas market is highly competitive, with many markets connected to multiple pipeline companies. We compete with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services.

          Rocky Mountain Natural Gas Pipeline Group

          The group, which operates primarily along the Rocky Mountain region of the Western portion of the United States, consists of the following four natural gas pipeline systems:

 

 

 

 

our Kinder Morgan Interstate Gas Transmission Pipeline;

 

 

 

 

our Trailblazer Pipeline;

 

 

 

 

our Trans-Colorado Pipeline; and

 

 

 

 

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

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powered by 28 transmission and storage compressor stations with approximately 160,000 horsepower. KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, 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 agricultural customers. The pipelines interconnecting with KMIGT in turn deliver gas into multiple markets including some of the largest population centers in the Midwest. Natural gas demand to power pumps for crop irrigation during the summer from time-to-time exceeds heating season demand and provides KMIGT relatively consistent volumes throughout the year. In addition, KMIGT has seen a significant increase in demand from ethanol producers, and is actively seeking ways to meet the demands from the ethanol producing community.

          Supply. Approximately 7%, by volume, of KMIGT’s firm contracts expire within one year and 51% expire within one to five years. Over 99% of the system’s total firm transport capacity is currently subscribed, with 78% of the total contracted capacity held by KMIGT’s top nine 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, 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, an investee of Knight, manages, maintains and operates Trailblazer, for which it is reimbursed at cost.

          Trailblazer provides transportation services to third-party natural gas producers, marketers, local distribution companies and other shippers. Pursuant to transportation agreements and FERC tariff provisions, Trailblazer offers its customers firm and interruptible transportation. Under Trailblazer’s tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported.

          Markets. Significant growth in Rocky Mountain natural gas supplies has prompted a need for additional pipeline transportation service. Trailblazer has a certificated capacity of 846 million cubic feet per day of natural gas.

          Supply. As of December 31, 2007, none of Trailblazer’s firm contracts, by volume, expire before one year and 54%, 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.

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          Competition. The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area either stays in the area or is moved west and therefore is not transported on Trailblazer’s pipeline. In addition, El Paso’s Cheyenne Plains Pipeline can transport approximately 730 million cubic feet per day of natural gas from Weld County, Colorado to Greensburg, Kansas and competes with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain area. Additional competition could come from the Rockies Express pipeline system or from 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, 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 39,000 horsepower. Knight manages, maintains and operates TransColorado, for which it is reimbursed at cost.

          TransColorado has the ability to flow gas south or north. TransColorado receives gas from one coal seam natural gas treating plant located in the San Juan Basin of Colorado and from pipeline, processing plant and gathering system interconnections within the Paradox and Piceance Basins of western Colorado. Gas flowing south through the pipeline moves onto the El Paso, Transwestern and Questar Southern Trail pipeline systems. Gas moving north flows into the Colorado Interstate, Wyoming Interstate and Questar pipeline systems at the Greasewood Hub and the Rockies Express pipeline system at the Meeker Hub. TransColorado provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers.

          Pursuant to transportation agreements and FERC tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. For these services, TransColorado charges rates which include the retention of fuel and gas lost and unaccounted for in-kind. Under TransColorado’s tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. The underlying reservation and commodity charges are assessed pursuant to a maximum recourse rate structure, which does not vary based on the distance gas is transported. TransColorado has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure.

          TransColorado’s approximately $50 million Blanco-Meeker Expansion Project was completed in the fourth quarter of 2007 and placed into service on January 1, 2008. The project boosted 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 2007, TransColorado transported an average of approximately 734 million cubic feet per day of natural gas from these supply basins.

          Supply. During 2007, 94% of TransColorado’s transport business was with producers or their own marketing affiliates, and 6% was with marketing companies and various gas marketers. Approximately 64% of TransColorado’s transport business in 2007 was conducted with its two largest customers. All of TransColorado’s southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2008. TransColorado’s pipeline capacity is 62% subscribed during 2009 through 2012, and TransColorado is actively pursuing contract extensions and or replacement contracts to increase firm subscription levels beyond 2008.

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          Competition. TransColorado competes with other transporters of natural gas in each of the natural gas supply basins it serves. These competitors include both interstate and intrastate natural gas pipelines and natural gas gathering systems. TransColorado’s shippers compete for market share with shippers drawing upon gas production facilities within the New Mexico portion of the San Juan Basin. TransColorado has phased its past construction and expansion efforts to coincide with the ability of the interstate pipeline grid at Blanco, New Mexico to accommodate greater natural gas volumes. TransColorado’s transport concurrently ramped up over that period such that TransColorado now enjoys a growing share of the outlet from the San Juan Basin to the southwestern United States marketplace.

          Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. New pipelines servicing these producing basins have had the effect of reducing that price differential; however, given the growth in the Piceance and Paradox basins 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 approximately $4.9 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.

          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 due to the fact that 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. We do not anticipate any additional changes in the ownership structure of the project.

          On August 9, 2005, the FERC approved Rockies Express Pipeline LLC’s application to construct 327 miles of pipeline facilities in two phases. Phase I consisted of the following two pipeline segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming; and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado. Phase II of the project includes the construction of three compressor stations referred to as the Meeker, Big Hole 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 is planned to commence in the second quarter of 2008, in order to meet an expected in-service date of June 30, 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) is expected to become fully operational in mid-March 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

21



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 issued a draft environmental report in late November 2007 for the REX-East Project, and subject to receipt of regulatory approvals, the REX-East Project is expected to begin partial service on December 31, 2008, and to be in full service in June 2009.

          In December 2007, Rockies Express Pipeline LLC completed a non-binding open season undertaken to solicit market interest for the “Northeast Express Project,” a 375-mile extension and expansion of the Rockies Express pipeline system from Clarington, Ohio, to Princeton, New Jersey. Significant expressions of interest were received on the Northeast Express Project and negotiations with prospective shippers to enter into binding commitments are currently underway. Subject to receipt of sufficient binding commitments and regulatory approvals, the Northeast Express Project would go into service in late 2010. When complete, the Northeast Express Project would provide up to 1.8 billion cubic feet of transportation capacity to northeast markets from the Lebanon Hub and other pipeline receipt points between Lebanon, Ohio and Clarington, Ohio.

          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. REX-West has 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 facilities or 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 under interim service is currently 1.4 billion cubic feet per day, and when this system is placed into full service it will be capable of delivering 1.5 billion cubic feet per day through these interconnects to the Midcontinent market.

          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 customers in Ohio.

          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.

22



          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 $510 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total.

          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). This segment is expected to be in service by January 1, 2009; 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. This portion of the project is expected to be in service in the third quarter of 2008.

          We have designed and will construct the Kinder Morgan Louisiana Pipeline in a manner that will minimize environmental impacts, and where possible, existing pipeline corridors will be used to minimize impacts to communities and to the environment. As of December 31, 2007, there were no major pipeline re-routes as a result of any landowner requests.

          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 total project is expected to cost approximately $1.3 billion, and will have an initial transportation capacity of approximately 1.4 billion cubic feet per day of natural gas.

          For additional information regarding the Midcontinent Express Pipeline, see “(a) General Development of Business—Recent Developments.”

          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

23



Paso. Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into KMIGT.

          Red Cedar Gathering Company

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

          Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. The inlet gas stream treated by Coyote Gulch contains an average carbon dioxide content of between 12% and 13%. The plant treats the gas down to a carbon dioxide concentration of 2% in order to meet interstate natural gas pipeline quality specifications, and then compresses the natural gas into the TransColorado Gas Transmission pipeline for transport to the Blanco, New Mexico-San Juan Basin Hub.

          Red Cedar’s gas gathering system currently consists of over 1,100 miles of gathering pipeline connecting more than 920 producing wells, 85,000 horsepower of compression at 24 field compressor stations and two carbon dioxide treating plants. The capacity and throughput of the Red Cedar system as currently configured is approximately 750 million cubic feet per day of natural gas.

          Thunder Creek Gas Services, LLC

          We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek. Devon Energy owns the remaining 75%. Thunder Creek provides gathering, compression and treating services to a number of coal seam gas producers in the Powder River Basin of Wyoming. Throughput volumes include both coal seam and conventional plant residue gas.

          Thunder Creek’s operations are a combination of mainline and low pressure gathering assets. The mainline assets include 125 miles of mainline pipeline, 230 miles of high and low pressure laterals, 26,635 horsepower of mainline compression and carbon dioxide removal facilities consisting of a 220 million cubic feet per day carbon dioxide treating plant complete with dehydration. The mainline assets receive gas from 53 receipt points and can deliver treated gas to seven delivery points including Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power plants. The low pressure gathering assets include five systems consisting of 194 miles of gathering pipeline and 35,329 horsepower of field compression.

          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. We are currently installing facilities and drilling 8 wells to increase the production capacity from

24



McElmo Dome by approximately 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 88% of the Doe Canyon Deep unit in Colorado, which contains more than 1.5 trillion cubic feet of carbon dioxide. We have installed facilities and drilled six wells to produce approximately 100 million cubic feet per day of carbon dioxide beginning in January 2008.

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

          Competition. Our primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves, and Petro-Source Carbon Company, which gathers waste carbon dioxide from natural gas production in the Val Verde Basin of West Texas. There is no assurance that new carbon dioxide sources will not be discovered or developed, which could compete with us or that new methodologies for enhanced oil recovery will not replace carbon dioxide flooding.

          Carbon Dioxide Pipelines

          As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% equity interest in and operate the approximate 500-mile, 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 one billion cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on our Central Basin pipeline and our Centerline pipeline. 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 600 million cubic feet per day. At its origination point in Denver City, our Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines (operated by 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 CO2 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.

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          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, a 21% net profits interest in the H.T. Boyd unit, an approximate 65% working interest in the Claytonville unit, an approximate 95% working interest in the Katz CB Long unit, an approximate 64% working interest in the Katz SW River unit, a 100% working interest in the Katz East River unit, and lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit, all of which are located in the Permian Basin of West Texas.

          The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.29 billion barrels of oil since inception. It is estimated that SACROC originally held approximately 2.7 billion barrels of oil. We have expanded the development of the carbon dioxide project initiated by the previous owners and increased production over the last several years. The Yates unit is also one of the largest oil fields ever discovered in the United States. It is estimated that it originally held more than five billion barrels of oil, of which about 29% has been produced. The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.

          As of December 2007, the SACROC unit had 391 producing wells, and the purchased carbon dioxide injection rate was 211 million cubic feet per day, down from an average of 247 million cubic feet per day as of December 2006. The average oil production rate for 2007 was approximately 27,600 barrels of oil per day, down from an average of approximately 30,800 barrels of oil per day during 2006. The average natural gas liquids production rate (net of the processing plant share) for 2007 was approximately 6,300 barrels per day, an increase from an average of approximately 5,700 barrels per day during 2006.

          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 as of December 2007, the Yates unit was producing about 27,600 barrels of oil per day. As of December 2006, the Yates unit was producing approximately 27,200 barrels of oil per day. Unlike our operations at SACROC, where we use carbon dioxide and water to drive oil to the producing wells, we are using carbon dioxide injection to replace nitrogen injection at Yates in order to enhance the gravity drainage process, as well as to maintain reservoir pressure. The differences in geology and reservoir mechanics between the two fields mean that substantially less capital will be needed to develop the reserves at Yates than is required at SACROC.

          We also operate and own an approximate 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 is currently producing approximately 230 barrels of oil per day. We are presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

          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, as of December 2007, was producing approximately 400 barrels of oil equivalent per day. We are presently evaluating operating and subsurface technical data to further assess redevelopment opportunities for the Katz field including the potential for carbon dioxide flood operations.

          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, 2007. 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:

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Productive Wells (a)

 

Service Wells (b)

 

Drilling Wells (c)

 

 

 


 


 


 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 


 


 


 


 


 


 

Crude Oil

 

 

2,463

 

 

1,587

 

 

1,066

 

 

789

 

 

2

 

 

2

 

Natural Gas

 

 

8

 

 

4

 

 

 

 

 

 

 

 

 

 

 



 



 



 



 



 



 

Total Wells

 

 

2,471

 

 

1,591

 

 

1,066

 

 

789

 

 

2

 

 

2

 

 

 



 



 



 



 



 



 



 

 

(a)

Includes active wells and wells temporarily shut-in. As of December 31, 2007, 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, 2007.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, 2007, 2006 and 2005:

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

Productive

 

 

 

 

 

 

 

 

 

 

Development

 

 

31

 

 

37

 

 

42

 

Exploratory

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

Development

 

 

 

 

 

 

 

Exploratory

 

 

 

 

 

 

 

 

 



 



 



 

Total Wells

 

 

31

 

 

37

 

 

42

 

 

 



 



 



 


 

 

Notes:

The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling operations were not completed as of the end of the applicable year. Development wells include wells drilled in the proved area of an oil or gas resevoir.

          The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2007:

 

 

 

 

 

 

 

 

 

 

Gross

 

Net

 

 

 


 


 

Developed Acres

 

 

72,435

 

 

67,731

 

Undeveloped Acres

 

 

8,788

 

 

8,129

 

 

 



 



 

Total

 

 

81,223

 

 

75,860

 

 

 



 



 

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          Operating Statistics

          Operating statistics from our oil and gas producing activities for each of the years 2007, 2006 and 2005 are shown in the following table:

Results of Operations for Oil and Gas Producing Activities – Unit Prices and Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 



 



 



 

Consolidated Companies(a)

 

 

 

 

 

 

 

 

 

 

Production costs per barrel of oil equivalent(b)(c)(d)

 

$

16.22

 

$

13.30

 

$

10.00

 

 

 



 



 



 

Crude oil production (MBbl/d)

 

 

35.6

 

 

37.8

 

 

37.9

 

 

 



 



 



 

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

 

 

5.5

 

 

5.0

 

 

5.3

 

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

 

 

4.1

 

 

3.9

 

 

4.1

 

 

 



 



 



 

Total natural gas liquids production(MBbl/d)

 

 

9.6

 

 

8.9

 

 

9.4

 

 

 



 



 



 

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

 

 

0.8

 

 

1.3

 

 

3.7

 

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

 

 

0.3

 

 

0.3

 

 

3.1

 

 

 



 



 



 

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

 

 

1.1

 

 

1.6

 

 

6.8

 

 

 



 



 



 

Average sales prices including hedge gains/losses:

 

 

 

 

 

 

 

 

 

 

Crude oil price per Bbl(g)

 

$

36.05

 

$

31.42

 

$

27.36

 

 

 



 



 



 

Natural gas liquids price per Bbl(g)

 

$

52.22

 

$

43.52

 

$

38.79

 

 

 



 



 



 

Natural gas price per Mcf(h)

 

$

6.08

 

$

6.36

 

$

5.84

 

 

 



 



 



 

Total natural gas liquids price per Bbl(e)

 

$

52.91

 

$

43.90

 

$

38.98

 

 

 



 



 



 

Total natural gas price per Mcf(e)

 

$

5.89

 

$

7.02

 

$

5.80

 

 

 



 



 



 

Average sales prices excluding hedge gains/losses:

 

 

 

 

 

 

 

 

 

 

Crude oil price per Bbl(g)

 

$

69.63

 

$

63.27

 

$

54.45

 

 

 



 



 



 

Natural gas liquids price per Bbl(g)

 

$

52.22

 

$

43.52

 

$

38.79

 

 

 



 



 



 

Natural gas price per Mcf(h)

 

$

6.08

 

$

6.36

 

$

5.84

 

 

 



 



 



 


 

 

(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 (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil.

 

 

(c)

Production costs include labor, repairs and maintenance, materials, supplies, fuel and power, property taxes, severance taxes, and general and administrative expenses directly related to oil and gas producing activities.

 

 

(d)

Includes only production attributable to leasehold ownership.

 

 

(e)

Includes production attributable to our ownership in processing plants and third party processing agreements.

 

 

(f)

Excludes natural gas production used as fuel.

 

 

(g)

Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.

 

 

(h)

Natural gas sales were not hedged.

          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 2007 was approximately 15,500 barrels per day as compared to 15,000 barrels per day as of December 2006.

          Crude Oil Pipeline

          We own our Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck delivery stations. The segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day. The pipeline allows us to better manage crude oil deliveries from our oil field interests in West Texas, and we have entered into a long-term throughput

28



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 approximately119,000 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 approximately100 owned or operated liquids and bulk terminal facilities, and more than 45 rail transloading and materials handling facilities located throughout the United States, Canada and the Netherlands. In 2007, the number of customers from whom our Terminals segment received more than $0.1 million of revenue was approximately 650.

          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 47.5 million barrels, and in 2007, these terminals handled approximately 557 million barrels of petroleum, chemicals and vegetable oil products.

          In September 2006, we announced major expansions at our Pasadena and Galena Park, Texas terminal facilities. The expansions will provide additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million includes the construction of the following: (i) new storage tanks at both our Pasadena and Galena Park terminals; (ii) an additional cross-channel pipeline to increase the connectivity between the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional loading bay at our fully automated truck loading rack located at our Pasadena terminal. The expansions are supported by long-term customer commitments and will result in approximately 3.4 million barrels of additional tank storage capacity at the two terminals. Construction began in October 2006, and all of the projects are expected to be completed by the spring of 2008, with the exception of the of the Galena Park ship dock which is now scheduled to be in-service by the third quarter of 2008.

          At Perth Amboy, New Jersey, we completed construction and placed into service nine new storage tanks with a 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 in these facilities was approximately $69 million.

          In June 2006, we announced the construction of a new crude oil tank farm located in Edmonton, Alberta, Canada, and long-term contracts with customers for all of the available capacity at the facility. Situated on approximately 24 acres, the new storage facility will have nine tanks with a combined storage capacity of approximately 2.2 million barrels for crude oil. Service is expected to begin in the first quarter of 2008, and when completed, the tank farm will serve as a premier blending and storage hub for Canadian crude oil. Originally estimated at $115 million, due primarily to additional labor costs, total investment in this tank farm is projected to be $162 million on a constant U.S. dollar basis. The tank farm will have 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 260,000 barrels per day of heavy crude oil and refined products from Edmonton to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state.

          Competition. We are one of the largest independent operators of liquids terminals in North America. Our primary competitors are IMTT, Magellan, Morgan Stanley, 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

29



handling, conveying, maintenance and repair, railcar switching and miscellaneous marine services. Combined, our dry-bulk and material transloading facilities handled approximately 87.1 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2007. We own or operate approximately 93 dry-bulk terminals in the United States, Canada and the Netherlands.

          In May 2007, we purchased certain buildings and equipment and completed a 40 year agreement to operate Vancouver Wharves, a bulk marine terminal located at the entrance to the Port of Vancouver, British Columbia. 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 the aggregate consideration of approximately $57.2 million ($38.8 million in cash and the assumption of $18.4 million of assumed liabilities) paid for this facility, we plan to invest an additional $46 million at Vancouver Wharves over the next two years to upgrade and relocate certain rail track and transloading systems, buildings and a shiploader.

          Effective September 1, 2007, we purchased the assets of Marine Terminals, Inc. for an aggregate consideration of approximately $101.5 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.

          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 45 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 2007, our materials services operations handled approximately 347,000 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.

          Trans Mountain

          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.

          Trans Mountain’s pipeline is 715 miles. The capacity of the line out of Edmonton ranges from 260,000 barrels per day when heavy crude represents 20% of the total throughput to 300,000 barrels per day with no heavy crude. The pipeline system utilizes 21 pump stations controlled by a centralized computer control system.

30



          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 2007, deliveries on Trans Mountain averaged 258,540 barrels per day. This was an increase of 13% from average 2006 deliveries of 229,369 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. 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 oilsands development with projects led by Shell Canada, Suncor Energy and Syncrude Canada. Further development is expected to continue into the future with expansions to existing oilsands production facilities as well as with new projects. In its moderate growth case, the Canadian Association of Petroleum Producers (“CAPP”) forecasts Western Canadian crude oil production to increase by over 1.6 million barrels per day by 2015. This increasing supply will likely result in constrained export pipeline capacity from Western Canada, which supports Trans Mountain’s 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 2007, shipments of refined petroleum and iso-octane represented 25% of throughput, as compared with 28% in 2006.

          Major Customers

          Our total operating revenues are derived from a wide customer base.For each of the years ended December 31, 2007, 2006 and 2005, 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 2007, 2006 and 2005 accounted for 63.3%, 66.8% and 73.9%, respectively, of our total consolidated revenues.

          As a result of our Texas intrastate group selling natural gas in the same price environment in which it is purchased, both our total consolidated revenues and our total consolidated purchases (cost of sales) increase considerably due to the inclusion of the cost of gas in both financial statement line items. However, these higher revenues and higher purchased gas costs do not necessarily translate into increased margins in comparison to those situations in which we charge a fee to transport gas owned by others as we seek to match the purchase and sales indexes and lock in a transport fee. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

          Regulation

          Interstate Common Carrier Pipeline Rate Regulation – 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, which tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the

31



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 system 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. In November 2004, Trans Mountain entered into negotiations with the Canadian Association of Petroleum Producers and principal shippers for a new incentive toll settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010. In January 2006, Trans Mountain reached agreement in principle, which was reduced to a memorandum of understanding for the 2006 toll settlement. A final agreement was reached with the Canadian Association of Petroleum Producers in October 2006 and NEB approval was received in November 2006.

          The 2006 toll settlement incorporates an incentive toll mechanism that is intended to provide Trans Mountain with the opportunity to earn a return on equity greater than that calculated using the formula established by the NEB. In return for this opportunity, Trans Mountain has agreed to assume certain risks and provide cost certainty in certain areas. Part of the incentive toll mechanism specifies that Trans Mountain is allowed to keep 75% of the net revenue generated by throughput in excess of 92.5% of the capacity of the pipeline. The 2006 incentive toll settlement provides for base tolls which will, other than recalculation or adjustment in certain specified circumstances, remain in effect for the five-year period. The toll settlement also governs the financial arrangements for the approximately C$638 million expansions to Trans Mountain that will add 75,000 barrels per day of incremental capacity to the system by November 2008. 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 Pipeline Rate Regulation – U.S. Operations.”

          Interstate Natural Gas Transportation and Storage Regulation

          Both the performance of and rates charged by companies performing interstate natural gas transportation and storage services are regulated by the FERC under the Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas Policy Act of 1978. Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

32



 

 

Order No. 436 (1985) requiring open-access, nondiscriminatory transportation of natural gas;

 

 

Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and

 

 

Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies whether purchased from the pipeline or from other merchants such as marketers or producers.

          Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage). Order 636 contains a number of procedures designed to increase competition in the interstate natural gas industry, including: (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 636 has been affirmed in all material respects upon judicial review, and our own FERC orders approving our unbundling plans are final and not subject to any pending judicial review.

          On November 25, 2003, the FERC issued Order No. 2004, adopting revised Standards of Conduct that apply uniformly to interstate natural gas pipelines and public utilities. In light of the changing structure of the energy industry, these Standards of Conduct govern relationships between regulated interstate natural gas pipelines and all of their energy affiliates. These new Standards of Conduct were designed to eliminate the loophole in the previous regulations that did not cover an interstate natural gas pipeline’s relationship with energy affiliates that are not marketers. The rule is designed to prevent interstate natural gas pipelines from giving an undue preference to any of their energy affiliates and to ensure that transmission is provided on a nondiscriminatory basis. In addition, unlike the prior regulations, these requirements apply even if the energy affiliate is not a customer of its affiliated interstate pipeline. Our interstate natural gas pipelines are in compliance with these Standards of Conduct.

          On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated Order No. 2004, as applied to natural gas pipelines, and remanded the Order back to the FERC. On January 9, 2007, the FERC issued an interim rule regarding standards of conduct in Order 690 to be effective immediately. The interim rule repromulgated the standards of conduct that were not challenged before the court. On January 18, 2007, the FERC issued a notice of proposed rulemaking soliciting comments on whether or not the interim rule should be made permanent for natural gas transmission providers.

          Please refer to Note 17 to our consolidated financial statements included elsewhere in this report for additional information regarding FERC Order No. 2004 and other Standards of Conduct rulemaking.

          On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, directed the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and significantly increased the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.

          California Public Utilities Commission Rate Regulation

          The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission, 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

33



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.

          Texas Railroad Commission Rate Regulation

          The intrastate common carrier 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. Although the Texas Railroad Commission has the authority to regulate our rates, the Commission has generally 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. We believe that we are in substantial compliance with U.S. DOT and comparable state regulations.

          The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. 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. The U.S. DOT has approved our qualification program. We believe that we are in substantial compliance with this law’s requirements and have integrated appropriate aspects of this pipeline safety law into our internal Operator Qualification Program. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001.

          We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes. We believe that we are in substantial compliance with Federal OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to hazardous substances.

          In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Some of these changes, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures. Such increases in our expenditures cannot be accurately estimated at this time.

          State and Local Regulation

          Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and safety.

          Environmental Matters

          Our operations are subject to federal, state and local, and some foreign laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations are in substantial compliance with applicable environmental laws and regulations.

34



          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 has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate our actual joint and several liability exposures. Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters will not have a material adverse effect on our business, financial position or results of operations. We have accrued an environmental reserve in the amount of $92.0 million as of December 31, 2007. Our reserve estimates range in value from approximately $92.0 million to approximately $142.7 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.

          Solid Waste

          We generate both hazardous and non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, state regulators and the United States Environmental Protection Agency consider the adoption of stricter disposal standards for non-hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during pipeline or liquids or bulk terminal operations, may in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

          Superfund

          The Comprehensive Environmental Response, Compensation and Liability Act, also known as the “Superfund” law or “CERCLA,” and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of “potentially responsible persons” for releases of “hazardous substances” into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the U.S. EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations, we have and will generate materials that may fall within the definition of “hazardous substance.” By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

          Clean Air Act

          Our operations are subject to the Clean Air Act, as amended, and analogous state statutes. We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes. The Clean Air Act, as amended, contains lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our 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.

          Due to the broad scope and complexity of the issues involved and the resultant complexity and nature of the regulations, full development and implementation of many Clean Air Act regulations by the U.S. EPA and/or various state and local regulators have been delayed. Therefore, until such time as the new Clean Air Act requirements are implemented, we are unable to fully estimate the effect on earnings or operations or the amount

35



and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements.

          Clean Water Act

          Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act as they pertain to prevention and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release. We believe we are in substantial compliance with these laws.

          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 December 31, 2007, KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. had, in the aggregate, approximately 7,600 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 2008 and 2012. 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.

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Item 1A. Risk Factors.

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

          Risks Related to Our Business

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

          Regulators and shippers on our pipelines have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates on our Pacific operations’ pipeline system. We may face challenges, similar to those described in Note 16 to our consolidated financial statements included elsewhere in this report, to the rates we receive on our pipelines in the future. Any successful challenge could adversely and materially affect our future earnings and cash flows.

          Rulemaking and oversight, as well as changes in regulations, by the Federal Energy Regulatory Commission or other regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.

          The rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers on our natural gas pipeline systems are subject to regulatory approval and oversight. Furthermore, regulators and shippers on our natural gas pipelines have rights to challenge the rates shippers are charged under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. Any successful challenge could materially adversely affect our future earnings and cash flows. New laws or regulations or different interpretations of existing laws or regulations applicable to our assets 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.

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

          We currently have several major expansion and new build projects planned or underway, including the approximate $4.9 billion Rockies Express Pipeline and the approximate $1.3 billion Midcontinent Express Pipeline. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors 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 results of operations and cash flows.

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          Our rapid growth may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions.

          Part of our business strategy includes acquiring additional businesses, expanding existing assets, or constructing new facilities that will allow us to increase distributions to our unitholders. If we do not successfully integrate acquisitions, expansions, or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:

 

 

 

 

demands on management related to the increase in our size after an acquisition, an expansion, or a completed construction project;

 

 

 

 

the diversion of our management’s attention from the management of daily operations;

 

 

 

 

difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems;

 

 

 

 

difficulties in the assimilation and retention of necessary employees; and

 

 

 

 

potential adverse effects on operating results.

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

          Our acquisition strategy and expansion programs require access to new capital. Tightened credit markets or more expensive capital would impair our ability to grow.

          Part of our business strategy includes acquiring additional businesses. We may need new capital to finance these acquisitions. Limitations on our access to capital will impair our ability to execute this strategy. We normally fund acquisitions with short-term debt and repay such debt through the issuance of equity and long-term debt. An inability to access the capital markets may result in a substantial increase in our leverage and have a detrimental impact on our credit profile.

          Environmental regulation and liabilities could result in increased operating and capital costs.

          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 products 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 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 federal, state and provincial environmental laws could require significant capital expenditures at our facilities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business.

          In addition, our oil and gas development and production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be

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abandoned and reclaimed to the satisfaction of state authorities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business.

          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 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 our 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 will be liable to perform on hedges currently valued at greater than $1.3 billion in favor of our counter-parties.

          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 and natural gas properties depend to a large degree on prevailing oil and gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things, weather conditions and events such as hurricanes in the United States; the condition of the United States economy; the activities of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign imports; and the availability of alternative fuel sources.

          A sharp decline in the price of natural gas or oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of oil and natural gas and could have a material adverse effect on the carrying value of our proved reserves. In the event prices fall substantially, we may not be able to realize a

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profit from our production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.

          Our use of hedging arrangements could result in financial losses or reduce our income.

          We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

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

          We do not own approximately 97.5% of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.

          We obtain the right to construct and operate pipelines on other owners’ land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be affected negatively.

          Whether we have the power of eminent domain for our pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas or carbon dioxide—and the laws of the particular state. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For the year ended December 31, 2007, all of our right-of-way related expenses totaled $14.6 million.

          Our debt instruments may limit our financial flexibility and increase our financing costs.

          The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. The agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (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.

          Because a portion of our debt is subject to variable interest rates, if interest rates increase, our earnings could be adversely affected.

          As of December 31, 2007, we had approximately $3.0 billion of debt, excluding the value of interest rate swaps, subject to variable interest rates. This amount included $2.3 billion of long-term fixed rate debt effectively converted to variable rate debt through the use of interest rate swaps. Should interest rates increase significantly, our earnings could be adversely affected. For information on our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

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          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 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.

          The general uncertainty associated with the current world economic and political environments in which we exist may adversely impact our financial performance.

          Our financial performance is impacted by overall marketplace spending and demand. We are continuing to assess the effect that terrorism would have on our businesses and in response, we have increased security with respect to our assets. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable throughout 2008.

          Knight’s recently completed going-private transaction resulted in substantially more debt at Knight and could have an adverse effect on us, such as a downgrade in the ratings of our debt securities.

          On May 30, 2007, Knight completed its going-private transaction. In connection with the transaction, Knight incurred substantially more debt. In conjunction with the going-private transaction, Moody’s Investor Service, Inc. and Standard & Poor’s Rating Services reviewed and adjusted the credit ratings of both Knight and us. Following these adjustments, our senior unsecured debt is rated BBB and Baa2 by Standard & Poor’s and Moody’s, respectively. 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. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007.

          Our senior management’s attention may be diverted from our daily operations because of recent significant transactions by Knight following the completion of the going-private transaction.

          The investors in Knight Holdco LLC include members of Knight’s senior management, most of whom are also senior officers of our general partner and of KMR. Prior to consummation of the going-private transaction, KMI had publicly disclosed that several significant transactions were being considered that, if pursued, would require substantial management time and attention. As a result, our senior management’s attention may be diverted from the management of our daily operations.

          Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates.

          Trans Mountain’s pipeline to the West Coast of North America is one of several pipeline alternatives for Western Canadian petroleum production. This pipeline, like all our petroleum pipelines, competes against other pipeline companies who could be in a position to offer different tolling structures, which may provide them with a competitive advantage in new pipeline development. Throughput on our pipelines may decline if tolls become uncompetitive compared to alternatives.

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          Future business development of our products pipelines is dependent on the supply of, and demand for, crude oil and other liquid hydrocarbons, particularly from the Alberta oilsands.

          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 oilsands. 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 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 oilsands. 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 our acquisition of the Trans Mountain pipeline system, the Vancouver Wharves terminal, the Cochin pipeline system, and our terminal expansion projects located in Edmonton, Alberta, Canada, 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.

          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 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 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).

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          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.

          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

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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.

          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.

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          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 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 federal income tax purposes. In order for us to be treated as a partnership for 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 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 federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Under current law, distributions to 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 federal income tax purposes or otherwise subject us to entity-level taxation. Members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly-traded partnerships. For example, 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 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 a new 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. Imposition of such a tax on us by Texas, or 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.

45



          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.

 

 

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 2007.

46



PART II

 

 

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Price Range

 

 

 

 

 

 

 

 

 


 

 

 

 

 

 

 

High

 

Low

 

Cash
Distributions

 

i-unit
Distributions

 

 

 


 


 


 


 

2007

 

 

 

 

 

 

 

 

 

 

 

 

 

First Quarter

 

$

53.50

 

$

47.28

 

$

0.8300

 

 

0.015378

 

Second Quarter

 

 

57.35

 

 

52.11

 

 

0.8500

 

 

0.016331

 

Third Quarter

 

 

56.70

 

 

46.61

 

 

0.8800

 

 

0.017686

 

Fourth Quarter

 

 

54.71

 

 

48.51

 

 

0.9200

 

 

0.017312

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

First Quarter

 

$

56.22

 

$

44.70

 

$

0.8100

 

 

0.018566

 

Second Quarter

 

 

48.80

 

 

43.62

 

 

0.8100

 

 

0.018860

 

Third Quarter

 

 

46.53

 

 

42.80

 

 

0.8100

 

 

0.018981

 

Fourth Quarter

 

 

48.98

 

 

43.01

 

 

0.8300

 

 

0.016919

 

          Distribution information is for distributions declared with respect to that quarter. The declared distributions were paid within 45 days after the end of the quarter. We currently expect to declare cash distributions of at least $4.02 per unit for 2008; 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, 2008, there were approximately 190,660 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 2007 or sell any unregistered units in the fourth quarter of 2007.

47



 

 

Item 6. Selected Financial Data

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007(6)

 

2006(7)

 

2005(8)

 

2004(9)

 

2003(10)

 

 

 


 


 


 


 


 

 

 

(In millions, except per unit and ratio data)

 

Income and Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

9,217.7

 

$

9,048.7

 

$

9,745.9

 

$

7,893.0

 

$

6,583.6

 

Costs, Expenses and Other:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas purchases and other costs of sales

 

 

5,809.8

 

 

5,990.9

 

 

7,167.3

 

 

5,767.0

 

 

4,880.0

 

Operations and maintenance

 

 

1,024.6

 

 

777.0

 

 

719.5

 

 

488.6

 

 

388.6

 

Fuel and power

 

 

237.5

 

 

223.7

 

 

178.5

 

 

146.4

 

 

102.2

 

Depreciation, depletion and amortization

 

 

540.0

 

 

423.9

 

 

341.6

 

 

281.1

 

 

212.2

 

General and administrative

 

 

278.7

 

 

238.4

 

 

216.7

 

 

170.5

 

 

150.5

 

Taxes, other than income taxes

 

 

153.8

 

 

134.4

 

 

106.5

 

 

79.1

 

 

60.3

 

Other expense (income)

 

 

365.6

 

 

(31.2

)

 

 

 

 

 

 

 

 



 



 



 



 



 

 

 

 

8,410.0

 

 

7,757.1

 

 

8,730.1

 

 

6,932.7

 

 

5,793.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

 

807.7

 

 

1,291.6

 

 

1,015.8

 

 

960.3

 

 

789.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income/(expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings from equity investments

 

 

69.7

 

 

74.0

 

 

89.6

 

 

81.8

 

 

91.2

 

Amortization of excess cost of equity investments

 

 

(5.8

)

 

(5.6

)

 

(5.5

)

 

(5.6

)

 

(5.5

)

Interest, net

 

 

(391.4

)

 

(337.8

)

 

(259.0

)

 

(192.9

)

 

(181.4

)

Other, net

 

 

14.2

 

 

12.0

 

 

3.3

 

 

2.2

 

 

7.6

 

Minority interest

 

 

(7.0

)

 

(15.4

)

 

(7.3

)

 

(9.6

)

 

(9.0

)

Income tax provision

 

 

(71.0

)

 

(29.0

)

 

(24.5

)

 

(19.7

)

 

(16.6

)

 

 



 



 



 



 



 

Income from continuing operations

 

 

416.4

 

 

989.8

 

 

812.4

 

 

816.5

 

 

676.1

 

Income (loss) from discontinued operations(1)

 

 

173.9

 

 

14.3

 

 

(0.2

)

 

15.1

 

 

17.8

 

 

 



 



 



 



 



 

Income before cumulative effect of a change in accounting principle

 

 

590.3

 

 

1,004.1

 

 

812.2

 

 

831.6

 

 

693.9

 

Cumulative effect of a change in accounting principle

 

 

 

 

 

 

 

 

 

 

3.4

 

 

 



 



 



 



 



 

Net income

 

$

590.3

 

$

1,004.1

 

$

812.2

 

$

831.6

 

$

697.3

 

Less: General Partner’s interest in net income

 

 

(611.6

)

 

(513.3

)

 

(477.3

)

 

(395.1

)

 

(326.5

)

 

 



 



 



 



 



 

Limited Partners’ interest in net income (loss)

 

$

(21.3

)

$

490.8

 

$

334.9

 

$

436.5

 

$

370.8

 

 

 



 



 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic Limited Partners’ net income (loss) per unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per unit from continuing operations and before cumulative effect of a change in accounting principle(2)

 

$

(0.82

)

$

2.12

 

$

1.58

 

$

2.14

 

$

1.89

 

Income from discontinued operations

 

 

0.73

 

 

0.07

 

 

 

 

0.08

 

 

0.09

 

Cumulative effect of a change in accounting principle

 

 

 

 

 

 

 

 

 

 

0.02

 

 

 



 



 



 



 



 

Net income (loss) per unit

 

$

(0.09

)

$

2.19

 

$

1.58

 

$

2.22

 

$

2.00

 

 

 



 



 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted Limited Partners’ net income (loss) per unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per unit from continuing operations and bef. cumulative effect of a change in acctg. principle(2)

 

$

(0.82

)

$

2.12

 

$

1.58

 

$

2.14

 

$

1.89

 

Income from discontinued operations

 

 

0.73

 

 

0.06

 

 

 

 

0.08

 

 

0.09

 

Cumulative effect of a change in accounting principle

 

 

 

 

 

 

 

 

 

 

0.02

 

 

 



 



 



 



 



 

Net income (loss) per unit

 

$

(0.09

)

$

2.18

 

$

1.58

 

$

2.22

 

$

2.00

 

 

 



 



 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per unit cash distribution declared(3)

 

$

3.48

 

$

3.26

 

$

3.13

 

$

2.87

 

$

2.63

 

Ratio of earnings to fixed charges(4)

 

$

2.13

 

$

3.64

 

 

3.76

 

 

4.84

 

 

4.68

 

Additions to property, plant and equipment

 

$

1,691.6

 

$

1,182.1

 

$

863.1

 

$

747.3

 

$

577.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data (at end of period):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net property, plant and equipment

 

$

11,591.3

 

$

10,106.1

 

$

8,864.6

 

$

8,168.9

 

$

7,091.6

 

Total assets

 

$

15,177.8

 

$

13,542.2

 

$

11,923.5

 

$

10,552.9

 

$

9,139.2

 

Long-term debt(5)

 

$

6,455.9

 

$

4,384.3

 

$

5,220.9

 

$

4,722.4

 

$

4,316.7

 

48




 

 

(1)

Represents income or loss from the operations of our North System natural gas liquids pipeline system. For 2007 only, also includes a gain of $152.8 million 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 before cumulative effect of a change in accounting principle per unit. Basic Limited Partners’ income per unit from continuing operations before cumulative effect of a change in accounting principle was computed by dividing the interest of our unitholders in income from continuing operations before cumulative effect of a change in accounting principle by the weighted average number of units outstanding during the period. Diluted Limited Partners’ net income per unit reflects the maximum potential dilution that could occur if units whose issuance depends on the market price of the units at a future date were considered outstanding, or if, by application of the treasury stock method, options to issue units were exercised, both of which would result in the issuance of additional units that would then share in our net income.

 

 

(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 cumulative effect of a change in accounting principle, and before minority interest in consolidated subsidiaries, equity earnings (including amortization of excess cost of equity investments) and unamortized capitalized interest, plus fixed 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 $152.2 million as of December 31, 2007, $42.6 million as of December 31, 2006, $98.5 million as of December 31, 2005, $130.2 million as of December 31, 2004, and $121.5 million as of December 31, 2003.

 

 

(6)

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.

 

 

(7)

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 due to the fact that regulatory accounting provisions required capitalization of revenues and expenses until the second segment of the Entrega Pipeline was complete and in-service.

 

 

(8)

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.

 

 

(9)

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

49



 

 

 

Fairless Hills terminal since effective dates of acquisition. We acquired the seven refined petroleum products terminals from ExxonMobil effective March 9, 2004. We acquired Kinder Morgan Wink Pipeline, L.P. effective August 31, 2004. The additional interest in Cochin was acquired effective October 1, 2004. We acquired Kinder Morgan River Terminals LLC and its consolidated subsidiaries effective October 6, 2004. We acquired TransColorado effective November 1, 2004, the interests in the nine Charter Terminal Company and Charter-Triad Terminals, LLC refined petroleum products terminals effective November 5, 2004, and the Kinder Morgan Fairless Hills terminal effective December 1, 2004.

 

 

(10)

Includes results of operations for the bulk terminal operations acquired from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC unit, the five refined petroleum products terminals acquired from Shell, the additional 42.5% interest in the Yates field unit, the crude oil gathering operations surrounding the Yates field unit, an additional 65% interest in the Pecos Carbon Dioxide Company, the remaining approximate 32% interest in MidTex Gas Storage Company, LLP, the seven refined petroleum products terminals acquired from ConocoPhillips and two bulk terminal facilities located in Tampa, Florida since dates of acquisition. We acquired certain bulk terminal operations from M.J. Rudolph effective January 1, 2003. The additional 12.75% interest in SACROC was acquired effective June 1, 2003. The five refined petroleum products terminals were acquired effective October 1, 2003. The additional 42.5% interest in the Yates field unit, the Yates gathering system and the additional 65% interest in Pecos Carbon Dioxide Company were acquired effective November 1, 2003. The additional 32% ownership interest in MidTex was acquired November 1, 2003. The seven refined petroleum products terminals were acquired December 11, 2003, and the two bulk terminal facilities located in Tampa, Florida were acquired effective December 10 and 23, 2003.


 

 

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

          The following discussion and analysis of our financial condition and results of operations provides a narrative of our financial results. It contains a discussion and analysis of the results of operations for each segment of our business, followed by a discussion and analysis of our financial condition. The following discussion and analysis is based on our consolidated financial statements, which are included elsewhere in this report and were prepared in accordance with accounting principles generally accepted in the United States of America.

          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 2007, 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, as discussed in Note 3 of the accompanying notes to our consolidated financial statements, our financial statements reflect:

 

 

 

 

the April 30, 2007 transfer of Trans Mountain as if such transfer had taken place on January 1, 2006, the effective date of common control pursuant to generally accepted accounting principles. The financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations includes the financial results of Trans Mountain for all periods subsequent to January 1, 2006; and

 

 

 

 

the reclassifications necessary to reflect the results of our North System as discontinued operations. However, due to the fact that 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 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.

          We begin with a discussion of our Critical Accounting Polices and Estimates, those areas that are both very important to the portrayal of our financial condition and results and which require our management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

50



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 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.

51



          Legal Matters

          We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.

          As of December 31, 2007, our most significant ongoing litigation proceedings involve our SFPP, L.P, subsidiary, which is the limited partnership that owns our Pacific operations’ pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by our Pacific operations’ pipeline systems are subject to certain proceedings at the FERC involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on our Pacific operations’ pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist. To the extent “substantially changed circumstances” are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by the FERC or the United States’ judicial system. For more information on our Pacific operations’ regulatory proceedings, see Note 16 to our consolidated financial statements included elsewhere in this report.

          Intangible Assets

          Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of Statement of Financial Accounting Standards No. 141, “Business Combinations” and Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to regular periodic amortization. Such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We have selected an impairment measurement test date of January 1 of each year, and we have determined that our goodwill was not impaired as of January 1, 2008.

          As of December 31, 2007, our goodwill was $1,077.8 million. Included in this goodwill balance is $251.0 million related to our Trans Mountain business segment, 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, 2007 and 2006, these intangibles totaled $238.6 million and $213.2 million, respectively.

          Estimated Net Recoverable Quantities of Oil and Gas

          We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are

52



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 floating interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes.

          According to the provisions of current accounting standards, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. A perfectly effective hedge is one in which changes in the value of the derivative contract exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the derivative contract. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately; accordingly, our financial statements may reflect some volatility due to these hedges.

          In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all, but due to the fact that the part of the hedging transaction that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

Results of Operations

 

 

 

 

Our business model is built to support two principal components:

 

 

 

 

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.

53



 

 

 

 

 

 

 

 

 

 

 

Consolidated

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

 

(In millions)

 

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

 

 

 

 

 

 

 

 

 

 

Products Pipelines(b)

 

$

569.6

 

$

491.2

 

$

370.1

 

Natural Gas Pipelines(c)

 

 

600.2

 

 

574.8

 

 

500.3

 

CO2 (d)

 

 

537.0

 

 

488.2

 

 

470.9

 

Terminals(e)

 

 

416.0

 

 

408.1

 

 

314.6

 

Trans Mountain(f)

 

 

(293.6

)

 

76.5

 

 

 

 

 



 



 



 

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

 

 

1,829.2

 

 

2,038.8

 

 

1,655.9

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization expense(g)

 

 

(547.0

)

 

(432.8

)

 

(349.8

)

Amortization of excess cost of equity investments

 

 

(5.8

)

 

(5.7

)

 

(5.6

)

Interest and corporate administrative expenses(h)

 

 

(686.1

)

 

(596.2

)

 

(488.3

)

 

 



 



 



 

Net income

 

$

590.3

 

$

1,004.1

 

$

812.2

 

 

 



 



 



 


 

 

(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)

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 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 resulting 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. 2005 amount includes a $105.0 million increase in expense resulting from a rate case liability adjustment, a $13.7 million increase in expense resulting from a North System liquids inventory reconciliation adjustment, and a $19.6 million increase in expense associated with environmental liability adjustments.

 

 

(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, 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. 2005 amount includes a $0.1 million reduction in expense associated with environmental liability adjustments.

 

 

(d)

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. 2005 amount includes a $0.3 million increase in expense associated with environmental liability adjustments.

 

 

(e)

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) an increase in income of $1.8 million from property casualty gains associated with the 2005 hurricane season; and (iv) a $1.2 million increase in expense associated with legal liability adjustments. 2006 amount includes an $11.3 million net 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). 2005 amount includes a $3.5 million increase in expense associated with environmental liability adjustments.

 

 

(f)

As discussed in Note 3 to our consolidated financial statements included elsewhere in this report, our consolidated financial statements, and all other financial information included in this report, are presented as though the April 30, 2007 transfer of Trans Mountain net assets had occurred on the date when both Trans Mountain and we met the accounting requirements for entities under common control (January 1, 2006). 2007 amount includes losses of $349.2 million for periods prior to our acquisition date of April 30, 2007 (including a goodwill impairment expense of $377.1 million), 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.

54




 

 

(g)

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 interest income and income tax expense, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses), and minority interest expense. 2007 amount includes the following: (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction. Knight Inc. was responsible for the payment of the costs resulting from this transaction; (ii) a combined $6.7 million increase in expense, related to Trans Mountain interest and general and administrative expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.4 million increase in interest expense related to our Cochin Pipeline acquisition; (iv) a $2.1 million expense due to the adjustment of certain insurance related liabilities; (v) a $1.7 million increase in expense associated with the 2005 hurricane season; (vi) a $1.5 million expense for certain Trans Mountain acquisition costs; (vii) a $0.8 million expense related to the cancellation of certain commercial insurance policies; and (viii) a total $3.9 million decrease in minority interest expense, related to the minority interest effect from all of the previously listed items. 2006 amount includes a combined $25.1 million expense related to Trans Mountain interest and general and administrative expenses, a $2.0 million increase in expense, primarily related to the cancellation of certain commercial insurance policies and a $3.5 million increase in minority interest expense, primarily related to the minority interest effect from the property casualty insurance gain described in footnote (e). 2005 amount includes a $25.0 million expense for a litigation settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system, a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the state of California, and a $3.0 million decrease in expense related to proceeds received in connection with the settlement of claims in the Enron Corp. bankruptcy proceeding.

          For the year 2007, our net income was $590.3 million on revenues of $9,217.7 million. This compares with net income of $1,004.1 million on revenues of $9,048.7 million in 2006, and net income of $812.2 million on revenues of $9,745.9 million in 2005. The certain items described in the footnotes to the table above account for $483.3 million of the year-to-year decrease of $413.8 million. The remaining increase in net income is associated with better performance from our operating segments.

          The primary reason for the decrease in our 2007 net income, when compared to last year, was related to 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. Also, our overall carrying value for the net assets of Trans Mountain reflects Knight’s carrying value, which is considerably higher than the cash price we paid. 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 consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above 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.

          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 strong financial results from 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 acquisition of the Trans Mountain pipeline system and the remaining interest in the Cochin pipeline system that we did not already own.

55



          In 2006, the certain items described above combined to increase total segment earnings before depreciation, depletion and amortization by$237.1 million, compared to the previous year (combining to increase total segment EBDA by $95.1 million in 2006 and to decrease segment EBDA by $142.0 million in 2005). The remaining $145.8 million (8%) increase in segment earnings before depreciation, depletion and amortization in 2006 versus 2005 was primarily attributable to internal growth and expansion across our business portfolio and to incremental contributions from assets and operations acquired since the end of 2005.

Products Pipelines

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

(In millions, except operating statistics)

 

Revenues

 

$

844.4

 

$

776.3

 

$

711.8

 

Operating expenses(a)

 

 

(451.8

)

 

(308.3

)

 

(366.0

)

Other income(b)

 

 

154.8

 

 

 

 

 

Earnings from equity investments(c)

 

 

32.5

 

 

16.3

 

 

28.5

 

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

 

 

9.4

 

 

12.1

 

 

6.1

 

Income tax benefit (expense)(e)

 

 

(19.7

)

 

(5.2

)

 

(10.3

)

 

 



 



 



 

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

 

$

569.6

 

$

491.2

 

$

370.1

 

 

 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

Gasoline (MMBbl)

 

 

435.5

 

 

449.8

 

 

452.1

 

Diesel fuel (MMBbl)

 

 

164.1

 

 

158.2

 

 

163.1

 

Jet fuel (MMBbl)

 

 

125.1

 

 

119.5

 

 

118.1

 

 

 



 



 



 

Total refined product volumes (MMBbl)

 

 

724.7

 

 

727.5

 

 

733.3

 

Natural gas liquids (MMBbl)

 

 

30.4

 

 

34.0

 

 

33.5

 

 

 



 



 



 

Total delivery volumes (MMBbl)(f)

 

 

755.1

 

 

761.5

 

 

766.8

 

 

 



 



 



 


 

 

(a)

2007, 2006 and 2005 amounts include increases in expense of $15.9 million, $13.5 million and $19.6 million, respectively, associated with environmental liability adjustments. 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. 2005 amount also includes a $105.0 million increase in expense associated with a rate case liability adjustment, and a $13.7 million increase in expense associated with a North System liquids inventory reconciliation adjustment.

 

 

(b)

2007 amount includes a $152.8 million gain from the sale of our North System.

 

 

(c)

2007 amount includes a $0.1 million increase in expense associated with our proportional share of legal liability adjustments on Plantation Pipe Line Company. 2006 amount includes a $4.9 million increase in expense associated with our proportional share of environmental liability adjustments on Plantation Pipe Line Company.

 

 

(d)

2007 amount includes a $1.8 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions. 2006 amount includes a $5.7 million increase in income resulting from transmix contract settlements.

 

 

(e)

2006 amount includes a $1.9 million decrease in expense associated with our proportional share of the tax effect on our share of environmental expenses incurred by Plantation Pipe Line Company and described in footnote (c).

 

 

(f)

Includes Pacific, Plantation, CALNEV, Central Florida, Cochin, and Cypress pipeline volumes.

          Our Products Pipelines segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transmix processing facilities. Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $5.5 million in 2007 compared to 2006, and increased earnings before depreciation, depletion and amortization by $127.5 million in 2006 compared to 2005.

          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 2007 and 2006, when compared to the respective prior year:

56



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2007 versus Year Ended December 31, 2006

 

 

EBDA

 

Revenues

 

 

 

increase/(decrease)

 

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

%

 

 



 

 

 

 



 

 

 

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2006 versus Year Ended December 31, 2005

 

 

EBDA

 

Revenues

 

 

 

Increase/(decrease)

 

increase/(decrease)

 

 

 


 


 

 

 

(In millions, except percentages)

 

Cochin Pipeline System

 

$

(5.2

)

 

(27

)%

$

(0.5

)

 

(1

)%

Southeast Terminals

 

 

4.9

 

 

15

%

 

24.5

 

 

43

%

Plantation Pipeline

 

 

(4.2

)

 

(12

)%

 

1.5

 

 

4

%

Pacific operations

 

 

(5.4

)

 

(2

)%

 

16.2

 

 

5

%

West Coast Terminals

 

 

(2.6

)

 

(7

)%

 

6.5

 

 

11

%

Transmix operations

 

 

2.6

 

 

13

%

 

3.9

 

 

13

%

All other (including eliminations)

 

 

3.5

 

 

3

%

 

12.4

 

 

8

%

 

 



 

 

 

 



 

 

 

 

Total Products Pipelines

 

$

(6.4

)

 

(1

)%

$

64.5

 

 

9

%

 

 



 

 

 

 



 

 

 

 

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

          The year-to-year earnings increase from our West Coast terminal operations in 2007 was due 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, partly due to completed storage expansion projects since the end of 2006, and from our Linnton and Willbridge terminals located in Portland, Oregon. The decrease in operating expenses in 2007 versus 2006 was largely related to higher environmental expenses recognized in 2006, due to adjustments to accrued environmental liabilities (these incremental environmental expenses were not associated with the expenses described in footnote (a) to the table above).

          The increase in earnings in 2007 from our approximate 51% equity investment in Plantation Pipe Line Company was due to higher overall net income earned by Plantation, largely resulting from both higher pipeline revenues and lower period-to-period operating expenses. The increase in revenues was largely due to a higher oil loss allowance percentage in 2007, relative to last year, and the drop in operating expenses—including fuel, power and pipeline maintenance expenses, was due to decreases in both refined products delivery volumes and pipeline integrity expenses in 2007 versus 2006 (pipeline integrity expenses are discussed more fully below).

          The year-to-year increase in earnings before depreciation, depletion and amortization from our petroleum pipeline transmix operations was directly related to higher revenues, reflecting incremental revenues from our Greensboro, North Carolina facility and higher processing revenues from our Colton, California facility. In May 2006, we completed construction and placed into service the Greensboro facility, and during 2007, the plant

57



processed greater volumes than in 2006. In 2007, our Greensboro facility contributed incremental earnings before depreciation, depletion and amortization of $4.5 million and incremental revenues of $5.4 million in 2007 compared to 2006. 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 year-to-year increases in average processing contract rates.

          We also benefited from higher earnings before depreciation, depletion and amortization from our Pacific operations, our CALNEV Pipeline and our North System in 2007, when compared to last year. The increase in our Pacific operations’ earnings was largely revenue related, attributable to increases in both 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. The increase from CALNEV was also 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. The increase from our North System was mainly due to lower combined operating expense, due to its sale in the fourth quarter of 2007 (the decline in expense was greater than the associated decline in revenue).

          Effective October 5, 2007, we sold our North System common carrier natural gas liquids pipeline and our 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million, and we used the proceeds we received to pay down short-term debt borrowings. We accounted for our North System business as a discontinued operation pursuant to generally accepted accounting principles which require that the income statement be formatted to separate the divested business from our continuing operations; however, consistent with the management approach of identifying and reporting 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 discussion and analysis. This decision was based on the way our management organizes segments internally to make operating decisions and assess performance. We do not expect the impact of the discontinued operations to materially affect our overall business, financial position, results of operations or cash flows. 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.

          Combining all of the segment’s operations, while revenues from refined petroleum products deliveries increased 6.2% in 2007, compared to last year, total refined products delivery volumes decreased 0.4%. Compared to last year, gasoline delivery volumes decreased 3.2% (primarily due to Plantation), while diesel and jet fuel volumes were up 3.7% and 4.7%, respectively. 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.

          The $6.4 million (1%) decrease in earnings before depreciation, depletion and amortization expenses in 2006, when compared to 2005, was largely due to a combined decrease in earnings of $24.2 million in 2006—due to incremental pipeline maintenance expenses recognized in the last half of the year. Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within our Products Pipelines segment (including Plantation Pipe Line Company, our 51%-owned equity investee) began recognizing certain costs incurred as part of their pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. Combined, this change reduced the segment’s earnings before depreciation, depletion and amortization expenses by $24.2 million in 2006—increasing maintenance expenses by $20.1 million, decreasing earnings from equity investments by $6.6 million, and decreasing income tax expenses by $2.5 million.

          Pipeline integrity costs encompass those costs incurred as part of an overall pipeline integrity management program, which is a process for assessing and mitigating pipeline risks in order to reduce both the likelihood and consequences of incidents. Our pipeline integrity program is designed to provide our management the information needed to effectively allocate resources for appropriate prevention, detection and mitigation activities.

58



          The remaining $17.8 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, primarily consisted of the following items:

 

 

 

 

a $4.9 million (15%) increase from our Southeast refined products terminal operations, driven by higher liquids throughput volumes at higher rates, relative to 2005, and higher margins from ethanol blending and sales activities;

 

 

 

 

a $4.1 million (1%) increase from our combined Pacific and CALNEV Pipeline operations, primarily due to a $22.6 million (6%) increase in operating revenues, which more than offset an $18.3 million (18%) increase in combined operating expenses. The increase in operating revenues consisted of a $14.7 million (5%) increase from refined products deliveries and a $7.9 million (8%) increase from terminal and other fee revenue. The increase in operating expenses was primarily due to higher fuel and power expenses; and

 

 

 

 

a $3.7 million (12%) increase from our Central Florida Pipeline, mainly due to higher product delivery revenues in 2006 driven by higher average tariff and terminal rates.

          Combining all of the segment’s operations, while total delivery volumes of refined petroleum products decreased 0.8% in 2006 compared to 2005, total delivery volumes from our Pacific operations were up 1.7% compared to 2005, due in part to the East Line expansion which was in service for the last seven months of 2006. The expansion project substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona. In addition, our CALNEV Pipeline delivery volumes were up 4.2% in 2006 versus 2005, due primarily to strong demand from the Southern California and Las Vegas, Nevada markets. The overall decrease in year-to-year segment deliveries of refined petroleum products was largely related to a 6.8% drop in volumes from the Plantation Pipeline in 2006, as described above.

          Natural Gas Pipelines

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

(In millions, except operating statistics)

 

Revenues

 

$

6,466.5

 

$

6,577.7

 

$

7,718.4

 

Operating expenses(a)

 

 

(5,882.9

)

 

(6,057.8

)

 

(7,255.0

)

Other income(b)

 

 

3.2

 

 

15.1

 

 

 

Earnings from equity investments(c)

 

 

19.2

 

 

40.5

 

 

36.8

 

Interest income and Other, net-income (expense)

 

 

0.2

 

 

0.7

 

 

2.7

 

Income tax benefit (expense)

 

 

(6.0

)

 

(1.4

)

 

(2.6

)

 

 



 



 



 

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

 

$

600.2

 

$

574.8

 

$

500.3

 

 

 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

Natural gas transport volumes (Trillion Btus)(d)

 

 

1,577.3

 

 

1,440.9

 

 

1,317.9

 

 

 



 



 



 

Natural gas sales volumes (Trillion Btus)(e)

 

 

865.5

 

 

909.3

 

 

924.6

 

 

 



 



 



 


 

 

(a)

2007, 2006 and 2005 amounts include a $0.4 million decrease in expense, a $1.5 million increase in expense and a $0.1 million decrease in expense, respectively, associated with environmental liability adjustments. 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)

Includes Rocky Mountain pipeline group and Texas intrastate natural gas pipeline group pipeline volumes.

 

 

(e)

Represents Texas intrastate natural gas pipeline group.

          Our Natural Gas Pipelines segment’s primary businesses involve marketing, transporting, storing, gathering, treating and processing natural gas through both intrastate and interstate pipeline systems and related facilities. Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $20.5 million in 2007, relative to 2006, and increased earnings before depreciation, depletion and amortization by $19.8 million in 2006, relative to 2005.

59



          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 2007 and 2006, when compared to the respective prior year:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2007 versus Year Ended December 31, 2006

 

 

 

 

 

EBDA
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

%

Rocky Mountain Pipeline Group

 

 

(11.6

)

 

(6

)%

 

29.0

 

 

10

%

Red Cedar Gathering Company

 

 

(7.4

)

 

(20

)%

 

 

 

 

All others

 

 

(0.7

)

 

(15

)%

 

(3.8

)

 

(94

)%

Intrasegment Eliminations

 

 

 

 

 

 

0.2

 

 

11

%

 

 



 

 

 

 



 

 

 

 

Total Natural Gas Pipelines

 

$

45.9

 

 

8

%

$

(111.2

)

 

(2

)%

 

 



 

 

 

 



 

 

 

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2006 versus Year Ended December 31, 2005

 

 

 

 

 

EBDA
Increase/(decrease)

 

Revenues
increase/(decrease)

 

 

 


 


 

 

 

(In millions, except percentages)

 

Texas Intrastate Natural Gas Pipeline Group

 

$

34.6

 

 

13

%

$

(1,165.7

)

 

(16

)%

Rocky Mountain Pipeline Group

 

 

14.3

 

 

8

%

 

27.9

 

 

11

%

Red Cedar Gathering Company

 

 

4.3

 

 

13

%

 

 

 

 

Casper and Douglas gas processing

 

 

2.9

 

 

30

%

 

(6.4

)

 

(6

)%

All others

 

 

(1.4

)

 

(21

)%

 

2.5

 

 

167

%

Intrasegment Eliminations

 

 

 

 

 

 

1.0

 

 

39

%

 

 



 

 

 

 



 

 

 

 

Total Natural Gas Pipelines

 

$

54.7

 

 

11

%

$

(1,140.7

)

 

(15

)%

 

 



 

 

 

 



 

 

 

 

          The segment’s overall increases in earnings before depreciation, depletion and amortization expenses in both 2007 and 2006 were driven by 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. Collectively, our Texas intrastate group serves the Texas Gulf Coast region by transporting, buying, selling, processing, treating and storing natural gas from multiple onshore and offshore supply sources.

          The higher earnings in both 2007 and 2006, when compared to the respective prior years, were primarily due to higher sales margins on renewal and incremental contracts, increased transportation revenue from higher volumes and rates, greater value from natural gas storage activities, and higher natural gas processing margins. Our Texas intrastate natural gas pipeline group also benefited, in 2007, from higher sales of cushion gas, due to the termination of a storage facility lease, and from incremental natural gas storage revenues, due to a long-term contract with one of its largest customers that became effective April 1, 2007. Although natural gas sales volumes were down almost 5% in 2007 compared to 2006, natural gas transport volumes on our Texas intrastate systems increased 21% in 2007 and 5% in 2006, resulting in higher year-over-year transportation revenues. Because the group also buys and sells natural gas, the variances from period to period in both segment revenues and segment operating expenses (which include natural gas costs of sales) are due to changes in our intrastate group’s average prices and volumes for natural gas purchased and sold.

          The increase in earnings from our Casper and Douglas natural gas processing operations in 2007, when compared to 2006, was driven by an overall 6% increase in operating revenues. The increase was primarily attributable to higher natural gas liquids sales revenues, due to increases in both prices and volume. The 2006 increase in earnings was primarily related to incremental earnings associated with favorable hedge settlements from our natural gas gathering and processing operations. We benefited from comparative differences in hedge settlements associated with the rolling-off of older low price crude oil and propane positions at December 31, 2005.

60



          The decrease in earnings in 2007 from our Rocky Mountain interstate natural gas pipeline group, which is comprised of Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, and our current 51% equity investment in Rockies Express Pipeline LLC, resulted primarily from a $12.6 million decrease in equity earnings from our investment in Rockies Express. The decrease in earnings from Rockies Express, which began interim service in February 2006, reflected lower net income due primarily to incremental depreciation and interest expense allocable to a segment of the project 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. Rockies Express-West is a 713-mile, 42-inch diameter natural gas pipeline that extends eastward from the Cheyenne Hub in Weld County, Colorado to Audrain County, Missouri. It has the capacity to transport up to 1.5 billion cubic feet of natural gas per day and it began interim service for up to 1.4 billion cubic feet per day on approximately 500 miles of line on January 12, 2008. Rockies Express-West is expected to become fully operational in mid-March 2008.

          The $14.3 million (8%) increase in earnings in 2006, relative to 2005, from our Rocky Mountain interstate natural gas pipeline group was driven by a $10.2 million (10%) increase in earnings from our Kinder Morgan Interstate Gas Transmission system and a $3.8 million (10%) increase from TransColorado Pipeline. The increase from KMIGT was due largely to higher revenues earned in 2006 from both operational sales of natural gas and natural gas park and loan services. KMIGT’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. The increase from TransColorado was largely due to higher natural gas transmission revenues earned in 2006 compared to 2005, chiefly related to higher natural gas delivery volumes resulting from both system improvements and the successful negotiation of incremental firm transportation contracts. The pipeline system improvements were associated with an expansion, completed since the end of the first quarter of 2005, on the northern portion of the pipeline.

          Both the drop, in 2007, and the increase, in 2006, in earnings before depreciation, depletion and amortization from our 49% equity investment in the Red Cedar Gathering Company were mainly due to higher prices on incremental sales of excess fuel gas and to higher natural gas gathering revenues in 2006, relative to both 2007 and 2005.

          CO2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

(In millions, except operating statistics)

 

Revenues(a)

 

 

$

824.1

 

 

 

$

736.5

 

 

 

$

657.6

 

 

Operating expenses(b)

 

 

 

(304.2

)

 

 

 

(268.1

)

 

 

 

(212.6

)

 

Other income

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings from equity investments

 

 

 

19.2

 

 

 

 

19.2

 

 

 

 

26.3

 

 

Other, net-income (expense)

 

 

 

 

 

 

 

0.8

 

 

 

 

 

 

Income tax benefit (expense)

 

 

 

(2.1

)

 

 

 

(0.2

)

 

 

 

(0.4

)

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

$

537.0

 

 

 

$

488.2

 

 

 

$

470.9

 

 

 

 

 



 

 

 



 

 

 



 

 

 

Carbon dioxide delivery volumes (Bcf)(c)

 

 

 

637.3

 

 

 

 

669.2

 

 

 

 

649.3

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

 

27.6

 

 

 

 

30.8

 

 

 

 

32.1

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

 

23.0

 

 

 

 

25.7

 

 

 

 

26.7

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

 

27.0

 

 

 

 

26.1

 

 

 

 

24.2

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

 

12.0

 

 

 

 

11.6

 

 

 

 

10.8

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

 

9.6

 

 

 

 

8.9

 

 

 

 

9.4

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

$

36.05

 

 

 

$

31.42

 

 

 

$

27.36

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

$

52.91

 

 

 

$

43.90

 

 

 

$

38.98

 

 

 

 

 



 

 

 



 

 

 



 

 


 

 


 

(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)

2007 and 2005 amounts include increases in expense associated with environmental liability adjustments of $0.2 million and $0.3 million, respectively.

61



 

 

(c)

Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.

 

 

(d)

Represents 100% of the production from the field. We own an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit.

 

 

(e)

Net to Kinder Morgan, 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.

          Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids.

          Combined, the certain items described in the footnotes to the table above increased earnings before depreciation, depletion and amortization by $1.6 million in 2007, relative to 2006, and decreased earnings before depreciation, depletion and amortization by $1.5 million in 2006, relative to 2005. For each of the segment’s two primary businesses, the following is information related to the remaining year-to-year increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:

Year Ended December 31, 2007 versus Year Ended December 31, 2006

 

 

 

 

 

 

 

 

 

 

 

EBDA

 

 

 

Revenues

 

 

 

increase/(decrease)

 

 

 

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

%

 

 

 

Year Ended December 31, 2006 versus Year Ended December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

EBDA

 

 

 

Revenues

 

 

 

increase/(decrease)

 

 

 

increase/(decrease)

 

 

 

(In millions, except percentages)

 

Sales and Transportation Activities

 

$

24.4

 

15

%

 

 

$

35.78

 

22

%

Oil and Gas Producing Activities

 

 

(5.6

)

(2

)%

 

 

 

57.1

 

10

%

Intrasegment Eliminations

 

 

 

 

 

 

 

(12.1

)

(25

)%

Total CO2

 

$

18.8

 

4

%

 

 

$

80.7

 

12

%

          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, which include its ownership interests in oil-producing fields and natural gas processing plants. 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—due largely 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 was primarily due to a decrease in carbon dioxide sales revenues, resulting mainly from lower average prices for carbon dioxide in 2007, and partly from a 3% drop in average carbon dioxide delivery 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 significantly high-priced sales contract in December 2006.

          The segment’s $18.8 million (4%) increase in earnings before depreciation, depletion and amortization in 2006 compared with 2005 was driven by higher earnings from the segment’s carbon dioxide sales and transportation activities, largely due to higher revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation. The overall increase in segment earnings before depreciation, depletion and amortization was partly offset by lower earnings from oil and gas producing activities and by lower equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company.

62



          The decrease in earnings from oil and gas producing activities in 2006 compared with 2005 was primarily due to higher combined operating expenses and to the previously disclosed drop in crude oil production at the SACROC oil field unit, discussed below. The higher operating expenses included higher field operating and maintenance expenses (including well workover expenses), higher property and severance taxes, and higher fuel and power expenses. The increases in expenses more than offset higher overall crude oil and natural gas plant product sales revenues, which increased primarily from higher realized sales prices and partly from higher crude oil production at the Yates field unit.

          The overall increases in segment revenues in 2007 and 2006, when compared to respective prior years, were mainly due to higher revenues from the segment’s oil and gas producing activities’ crude oil sales and natural gas liquids sales. Combined, crude oil and plant product sales revenues increased $77.9 million (14%) in 2007 compared to 2006, and $63.9 million (12%) in 2006 compared to 2005.

          The year-over-year increases in revenues from the sales of natural gas liquids were driven by favorable sales price variances—our realized weighted average price per barrel increased 21% in 2007 and 13% in 2006, when compared to the respective prior year. The year-over-year increases in revenues from the sales of crude oil reflected annual increases in our realized weighted average price per barrel of 15% in both 2007 and 2006, and although total crude oil sales volumes were relatively flat in 2006 compared to 2005, sales volumes decreased 6% in 2007 compared to 2006. Average gross oil production for 2007 was 27.0 thousand barrels per day at the Yates unit, up 3% from 2006, and 27.6 thousand barrels per day at SACROC, a decline of 10% versus 2006.

          The year-to-year decline in crude oil production at the SACROC field unit is attributable to lower observed recoveries from recent project areas and due 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.

          In addition, because our CO2 segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, we 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. 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 $69.63 per barrel in 2007, $63.27 per barrel in 2006 and $54.45 per barrel in 2005. For more information on our hedging activities, see Note 14 to our consolidated financial statements included elsewhere in this report.

          Terminals

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

(In millions, except operating statistics)

 

Revenues

 

 

$

963.7

 

 

 

$

864.8

 

 

 

$

699.3

 

 

Operating expenses(a)

 

 

 

(536.4

)

 

 

 

(461.9

)

 

 

 

(373.4

)

 

Other income(b)

 

 

 

6.3

 

 

 

 

15.2

 

 

 

 

 

 

Earnings from equity investments

 

 

 

0.6

 

 

 

 

0.2

 

 

 

 

0.1

 

 

Other, net-income (expense)

 

 

 

1.0

 

 

 

 

2.1

 

 

 

 

(0.2

)

 

Income tax benefit (expense)(c)

 

 

 

(19.2

)

 

 

 

(12.3

)

 

 

 

(11.2

)

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

$

416.0

 

 

 

$

408.1

 

 

 

$

314.6

 

 

 

 

 



 

 

 



 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Bulk transload tonnage (MMtons)(d)

 

 

 

87.1

 

 

 

 

95.1

 

 

 

 

85.5

 

 

 

 

 



 

 

 



 

 

 



 

 

Liquids leaseable capacity (MMBbl)

 

 

 

47.5

 

 

 

 

43.5

 

 

 

 

42.4

 

 

 

 

 



 

 

 



 

 

 



 

 

Liquids utilization %

 

 

 

95.9

%

 

 

 

96.3

%

 

 

 

95.4

%

 

 

 

 



 

 

 



 

 

 



 

 

63



 

 

(a)

2007 and 2005 amounts include increases in expense associated with environmental liability adjustments of $2.0 million and $3.5 million, respectively.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.

 

 

(b)

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)

2006 amount includes a $1.1 million increase in expense associated with hurricane expenses and casualty gain.

 

 

(d)

Volumes for acquired terminals are included for 2007 and 2006.

          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 other dry-bulk material services facilities.

          Combined, the certain items described in the footnotes to the table above decreased earnings before depreciation, depletion and amortization by $37.7 million in 2007, relative to 2006, and increased earnings before depreciation, depletion and amortization by $14.8 million in 2006, relative to 2005. The segment’s remaining $45.6 million (11%) increase in earnings before depreciation, depletion and amortization expenses in 2007 compared with 2006, and its remaining $78.7 million (25%) increase in 2006 compared to 2005, were driven by a combination of internal expansions and strategic acquisitions completed since the end of 2005. 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 storage, handling and throughput capacity.

          In 2007, we invested approximately $158.9 million to acquire terminal assets and equity investments, and our significant terminal acquisitions since the fourth quarter of 2006 included the following:

 

 

 

 

all of the membership interests of Transload Services, LLC, which provides material handling and steel processing services at 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States, acquired November 20, 2006;

 

 

 

 

all of the membership interests of Devco USA L.L.C., which includes a proprietary technology that transforms molten sulfur into solid pellets that are environmentally friendly and easier to transport, acquired December 1, 2006;

 

 

 

 

the Vancouver Wharves bulk marine terminal, which includes five deep-sea vessel berths and terminal assets located on the north shore of the Port of Vancouver’s main harbor. The assets include significant rail infrastructure, dry bulk and liquid storage, and material handling systems, and were acquired May 30, 2007; and

 

 

 

 

the terminal assets and operations acquired from Marine Terminals, Inc., which are primarily involved in the handling and storage of steel and alloys and consist of two separate facilities located in Blytheville, Arkansas, and individual terminal facilities located in Decatur, Alabama, Hertford, North Carolina, and Berkley, South Carolina. The assets were acquired effective September 1, 2007.

          Combined, these 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 amounts represent the earnings, revenues and expenses from the acquired terminals’ operations during the additional months of ownership in 2007, and do not include increases or decreases during the same months we owned the assets in 2006.

          In 2006, we also benefited significantly from the incremental contributions attributable to the bulk and liquids terminal businesses we acquired during 2005 and 2006. In addition to the two acquisitions acquired in the fourth quarter of 2006 and referred to above, these acquisitions included the following significant businesses:

 

 

 

 

our Texas Petcoke terminals, located in and around the Ports of Houston and Beaumont, Texas, acquired effective April 29, 2005;

64



 

 

 

 

three terminals acquired separately in July 2005: our Kinder Morgan Staten Island terminal, a dry-bulk terminal located in Hawesville, Kentucky and a liquids/dry-bulk facility located in Blytheville, Arkansas; and

 

 

 

 

all of the ownership interests in General Stevedores, L.P., which operates a break-bulk terminal facility located along the Houston Ship Channel, acquired effective July 31, 2005.

          Combined, these terminal acquisitions accounted for incremental amounts of earnings before depreciation, depletion and amortization of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues and expenses were attributable to the inclusion of our Texas petroleum coke terminals, which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate consideration of approximately $247.2 million. The primary assets acquired included facilities and railway equipment located at the Port of Houston, the Port of Beaumont and the TGS Deepwater terminal located on the Houston Ship Channel.

          For all other terminal operations (those owned during identical periods in both 2007 and 2006), earnings before depreciation, depletion and amortization expenses increased $14.4 million (4%) in 2007, and $45.2 million (14%) in 2006, when compared to the respective prior years. The increases in earnings represent net changes in terminal results at various locations, but the year-over-year increase in 2007 compared to 2006 was largely due to higher earnings in 2007 from our two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas. The two terminals continued to benefit from both recent expansions that have added new liquids tank and truck loading rack capacity since 2006, and incremental business from ethanol and biodiesel storage and transfer activity (for the entire segment, our expansion projects and acquisitions completed since the end of 2006 have increased our liquids terminals’ leaseable capacity by 9%, more than offsetting a less than 1% drop in our overall utilization percentage). Higher earnings in 2007 also resulted from (i) the combined operations of our Argo and Chicago, Illinois liquids terminals, due to increased ethanol throughput and incremental liquids storage and handling business; (ii) our Texas Petcoke terminals, due largely to higher petroleum coke throughput volumes at our Port of Houston facility; and (iii) our Pier IX bulk terminal, located in Newport News, Virginia, largely due to a 19% year-to-year increase in coal transfer volumes and higher rail incentives.

          The increase in earnings in 2006 compared to 2005 from terminals owned during both years included higher earnings in 2006 from (i) our Pasadena and Galena Park Gulf Coast liquids terminals, driven by higher revenues, in 2006, from new and incremental customer agreements, additional liquids tank capacity from capital expansions completed at our Pasadena terminal since the end of 2005, higher truck loading rack service fees, higher ethanol throughput, and incremental revenues from customer deficiency charges; (ii) our Shipyard River terminal, located in Charleston, South Carolina, due to higher revenues from liquids warehousing and coal and cement handling; (iii) our Texas Petcoke terminals, mainly resulting from an increase in petroleum coke handling volumes; and (iv) our Lower Mississippi River (Louisiana) terminals, primarily due to incremental earnings from our Amory and DeLisle Mississippi bulk terminals. Our Amory terminal began operations in July 2005. The higher earnings from our DeLisle terminal, which was negatively impacted by hurricane damage in 2005, was primarily due to higher bulk transfer revenues in 2006.

          Trans Mountain

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

 


 

 

 

2007

 

2006(c)

 

2005

 

 

 


 


 


 

 

 

(In millions, except operating statistics)

 

Revenues

 

 

$

160.8

 

 

 

$

137.8

 

 

 

$

 

 

Operating expenses

 

 

 

(65.9

)

 

 

 

(53.3

)

 

 

 

 

 

Other income (expense)(a)

 

 

 

(377.1

)

 

 

 

0.9

 

 

 

 

 

 

Earnings from equity investments

 

 

 

 

 

 

 

 

 

 

 

 

 

Other, net-income (expense)

 

 

 

8.0

 

 

 

 

1.0

 

 

 

 

 

 

Income tax benefit (expense)

 

 

 

(19.4

)

 

 

 

(9.9

)

 

 

 

 

 

 

 

 



 

 

 



 

 

 



 

 

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

 

 

$

(293.6

)

 

 

$

76.5

 

 

 

$

 

 

 

 

 



 

 

 



 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transport volumes (MMBbl)

 

 

 

94.4

 

 

 

 

83.7

 

 

 

 

 

 

 

 

 



 

 

 



 

 

 



 

 

65



 

 

(a)

2007 amount represents a goodwill impairment expense recorded by Knight in the first quarter of 2007.

 

 

(b)

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.

 

 

(c)

2006 amounts relate to periods prior to our acquisition date of April 30, 2007. See discussion below.

          Our Trans Mountain segment includes the operations of the Trans Mountain Pipeline, which we acquired from Knight effective April 30, 2007. Trans Mountain transports crude oil and refined products from Edmonton, Alberta to marketing terminals and refineries in British Columbia and the state of Washington. An additional 35,000 barrel per day expansion that will increase capacity on the pipeline to approximately 300,000 barrels per day is currently under construction and is expected to be in service by late 2008.

          According to the provisions of generally accepted accounting principles that prescribe the standards used to account for business combinations, due to the fact that our acquisition of Trans Mountain from Knight represented a transfer of assets between entities under common control, we initially recorded the assets and liabilities of Trans Mountain transferred to us from Knight at their carrying amounts in the accounts of Knight. Furthermore, our accompanying financial statements included in this report, and the information in the table above, reflect the results of operations for both 2007 and 2006 as though the transfer of Trans Mountain from Knight had occurred at the beginning of the period (January 1, 2006 for us).

          After taking into effect the certain items described in the footnotes to the table above, the remaining increase in earnings before depreciation, depletion and amortization in 2007 versus 2006 totaled $56.9 million, and related entirely to our acquisition of Trans Mountain effective April 30, 2007.

          Other

 

Year Ended
December 31,

 

 


Earnings

 

2007

 

2006

 

 

increase/(decrease)

 

(In millions-income (expense), except

percentages)

General and administrative expenses(a)

$

(278.7

)

 

$

(238.4

)

 

 

$

(40.3

)

 

(17

)%

Interest expense, net of unallocable 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 corporate administrative expenses

$

(686.1

)

 

$

(596.2

)

 

 

$

(89.9

)

 

(15

)%

 

 

 

 

Year Ended
December 31,

 

 


Earnings

 

2006

 

2005

 

 

increase/(decrease)

 

(In millions-income (expense), except

percentages)

General and administrative expenses(a)

$

(238.4

)

 

$

(216.7

)

 

 

$

(21.7

)

 

(10

)%

Interest expense, net of unallocable interest income(b)

 

(342.4

)

 

 

(264.3

)

 

 

 

(78.1

)

 

(30

)%

Minority interest(c)

 

(15.4

)

 

 

(7.3

)

 

 

 

(8.1

)

 

(111

)%

Total interest and corporate administrative expenses

$

(596.2

)

 

$

(488.3

)

 

 

$

(107.9

)

 

(22

)%



 

 


(a)

2007 amount includes (i) a $26.2 million increase in expense, allocated to us from Knight, associated with closing the going-private transaction. Knight Inc. was responsible for the payment of the costs resulting from this transaction; (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 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 Trans Mountain expenses of $18.8 million, a $2.4 million increase in expense related to the cancellation of certain commercial insurance policies, and 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. 2005 amount includes a $25.0 million expense for a litigation settlement reached between us and a former joint venture partner on our Kinder Morgan Tejas natural gas pipeline system, a cumulative $8.4 million expense related to settlements of environmental matters at certain of our operating sites located in the state of California, and a $3.0 million decrease in expense related to proceeds received in connection with the settlement of claims in the Enron Corp. bankruptcy proceeding.

 

 

66



 

 

(b)

2007 amount includes a $2.4 million increase in expense related to imputed interest on our Cochin Pipeline acquisition, and Trans Mountain expenses of $1.2 million for periods prior to our acquisition date of April 30, 2007. 2006 amount includes Trans Mountain expenses of $6.3 million.

 

 

(c)

2007 amount includes a $3.9 million decrease in expense, related to the minority interest effect from all of the 2007 items listed in footnotes (a) and (b). 2006 amount includes a $3.5 million increase in expense, primarily related to the minority interest effect from the property casualty insurance gain associated with the 2005 hurricane season.

          Items not attributable to any segment include general and administrative expenses, unallocable interest income and income tax expense, interest expense and minority interest. Our general and administrative expenses include such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services—including accounting, information technology, human resources and legal services.

          Compared to 2006, the certain items described in footnote (a) to the tables above increased our 2007 general and administrative expenses by $17.0 million. The remaining $23.3 million (11%) increase in expenses was largely due to (i) higher shared services expenses, which include legal, corporate secretary, tax, information technology and other shared services; and (ii) higher payroll-related expenses resulting from the acquisitions and incremental expansions we have made since the end of 2006.

          Compared to 2005, the certain items described in footnote (a) decreased our 2006 general and administrative expenses by $9.6 million. The remaining $31.3 million (17%) increase in overall general and administrative expenses in 2006 compared to 2005 was primarily due to higher corporate service charges and higher corporate and employee-related insurance expenses in 2006. The increase in corporate services was largely due to higher corporate overhead expenses associated with the business operations we acquired since the end of 2005. The increase in insurance expenses was partly due to incremental expenses related to the cancellation of certain commercial insurance polices, as well as to the overall variability in year-to-year commercial property and medical insurance costs. Pursuant to certain provisions that gave us the right to cancel certain commercial policies prior to maturity, we took advantage of the opportunity to reinsure at lower rates.

          Interest expense, net of unallocable interest income, totaled $395.8 million in 2007, $342.4 million in 2006 and $264.3 million in 2005. Compared to 2006, net interest expense decreased $2.7 million in 2007 due to the items described in footnote (b) to the tables above. The remaining $56.1 million (17%) increase in expense in 2007 compared to 2006 was due to both a 4% increase in average borrowing rates (the weighted average interest rate on all of our borrowings was approximately 6.40% during 2007 and 6.18% during 2006) and a 17% increase in average borrowings (excluding the market value of interest rate swaps). The increase in average borrowings was mainly due to capital spending in 2007, and the acquisition of external assets and businesses since the end of 2006.

          We incurred incremental net interest expense of $6.3 million in 2006 due to the inclusion of Trans Mountain, and the remaining $71.8 million (27%) increase in expense in 2006 compared to 2005 was due to both higher average debt levels and higher effective interest rates. In 2006, average borrowings increased 10% and the weighted average interest rate on all of our borrowings increased 17%, when compared to 2005 (the weighted average interest rate on all of our borrowings was approximately6.18% during 2006 and 5.30% during 2005).

          Generally, we initially fund both our capital spending (including payments for pipeline project construction costs) and our acquisition outlays from borrowings under our commercial paper program. From time to time, we issue senior notes in order to refinance our commercial paper borrowings. For more information on our capital expansion and acquisition expenditures, see “—Liquidity and Capital Resources—Investing Activities.”

          The year-to-year increases in our average borrowing rates in 2007 and 2006 reflect a general rise in variable interest rates since the end of 2005. We use interest rate swap agreements to help manage our interest rate risk. The swaps are contractual agreements we enter into in order to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. However, in a period of rising interest rates, these swaps will result in period-to-period increases in our interest expense. For more information on our interest rate swaps, see Note 14 to our consolidated financial statements, included elsewhere in this report.

67



          Liquidity and Capital Resources

          Capital Structure

          We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.” The following table illustrates the sources of our invested capital (dollars in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

Long-term debt, excluding market value of interest rate swaps

 

$

6,455.9

 

$

4,384.3

 

$

5,220.9

 

Minority interest

 

 

54.2

 

 

60.2

 

 

42.3

 

Partners’ capital, excluding accumulated other comprehensive loss

 

 

5,712.3

 

 

5,814.4

 

 

4,693.5

 

 

 



 



 



 

Total capitalization

 

 

12,222.4

 

 

10,258.9

 

 

9,956.7

 

Short-term debt, less cash and cash equivalents

 

 

551.3

 

 

1,352.4

 

 

(12.1

)

 

 



 



 



 

Total invested capital

 

$

12,773.7

 

$

11,611.3

 

$

9,944.6

 

 

 



 



 



 

 

 

 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

 

 

 

 

Long-term debt, excluding market value of interest rate swaps

 

 

52.8

%

 

42.7

%

 

52.4

%

Minority interest

 

 

0.5

%

 

0.6

%

 

0.4

%

Partners’ capital, excluding accumulated other comprehensive loss

 

 

46.7

%

 

56.7

%

 

47.2

%

 

 



 



 



 

 

 

 

100.0

%

 

100.0

%

 

100.0

%

 

 



 



 



 

Invested Capital:

 

 

 

 

 

 

 

 

 

 

Total debt, less cash and cash equivalents and excluding market value of interest rate swaps

 

 

54.9

%

 

49.4

%

 

52.4

%

Partners’ capital and minority interest, excluding accumulated other comprehensive loss

 

 

45.1

%

 

50.6

%

 

47.6

%

 

 



 



 



 

 

 

 

100.0

%

 

100.0

%

 

100.0

%

 

 



 



 



 

          Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements for expansion capital expenditures through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.

          In general, we expect to fund:

 

 

 

 

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.

 

 

 

          As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. We are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors.

68



          As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and internal growth activities in order to maintain acceptable financial ratios.

          On May 30, 2006, Standard & Poor’s Rating Services and Moody’s Investors Service each placed our ratings on credit watch pending the resolution of KMI’s going-private transaction. On January 5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to BBB and removed our rating from credit watch with negative implications. Currently, our debt credit rating is still rated BBB by S&P. 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.

          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 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 principal sources of short-term liquidity are (i) our $1.85 billion five-year senior unsecured revolving credit facility that matures August 18, 2010; (ii) our $1.85 billion short-term commercial paper program (which is supported by our bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings); and (iii) cash from operations (discussed following).

          Borrowings under our five-year credit facility can be used for general partnership purposes and as a backup for our commercial paper program. The facility can be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our credit facility as of December 31, 2007. As of December 31, 2007, we had $589.1 million of commercial paper outstanding.

          We provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our commercial paper program and long-term revolving credit facility. After reduction for our outstanding commercial paper borrowings and letters of credit, the remaining available borrowing capacity under our bank credit facility was $723.1 million as of December 31, 2007. As of December 31, 2007, our outstanding short-term debt was $610.2 million. Currently, we believe our liquidity to be adequate. For more information on our commercial paper program and our credit facility, see Note 9 to our consolidated financial statements included elsewhere in this report.

          Long-term Financing

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

          We are subject, however, to changes in the equity and debt markets for our limited partner units and long-term notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited

69



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. Our ability to access the public and private debt markets is affected by our credit ratings. See “—Capital Structure” above for a discussion of our credit ratings.

          Equity 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 5,700,000 i-units.

          On December 5, 2007, we completed a public offering of 7,130,000 of our common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 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 equity 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 valued at $15.0 million.

          On February 12, 2008, we completed an additional offering of 1,080,000 of our common units at a price of $55.65 per unit in a privately negotiated transaction with two investors. 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.

          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.

          During 2007, we completed three separate public offerings of senior notes. We received proceeds, net of underwriting discounts and commissions, as follows:

 

 

 

 

$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;

 

 

 

 

$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

 

 

 

 

$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.

 

 

 

          We used the proceeds from each of these three debt offerings to reduce the borrowings under our commercial paper program. In addition, on August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on that date. As of December 31, 2007, our total liability balance due on the various series of our senior notes was $6,288.8 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $188.2 million. For additional information regarding our debt securities, see Note 9 to our consolidated financial statements included elsewhere in this report.

70



          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 received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $894.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

          Capital Requirements for Recent Transactions

          During 2007, our cash ou