Kinder Morgan, Inc. 2006 Form 10-K

Table of Contents


KMI Form 10-K





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

FORM 10-K

þ

  

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31, 2006

or

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 1-06446

Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)

Kansas

  

48-0290000

(State or other jurisdiction of incorporation or organization)

  

(I.R.S. Employer Identification No.)


500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices, including 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 stock, par value $5 per share

  

New York Stock Exchange


Securities registered pursuant to section 12(g) of the Act:

Preferred stock, Class A $5 cumulative series

(Title of class)


Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

Yes þ  No o

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:

Yes o  No þ

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 þ  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.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):  Large accelerated filer þ  Accelerated filer o  Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o  No þ




KMI Form 10-K



The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $10,705,381,712 at June 30, 2006.

The number of shares outstanding of the registrant’s common stock, $5 par value, as of January 31, 2007 was 134,188,793 shares.



2



KMI Form 10-K



KINDER MORGAN, INC. AND SUBSIDIARIES
CONTENTS

 

 

Page
Number

 

PART I

 

 

Items 1 and 2:

Business and Properties

5-55

 

 

 

Business Strategy

6

 

 

 

Recent Developments

7

 

 

  

Overview

15

 

 

  

Natural Gas Pipeline Company of America

16

 

 

 

Kinder Morgan Canada (Formerly Terasen Pipelines)

 

18

 

 

 

Terasen Gas

20

 

 

  

Power

23

 

 

 

Products Pipelines – KMP

24

 

 

 

Natural Gas Pipelines – KMP

31

 

 

 

CO2 – KMP

37

 

 

 

Terminals – KMP

42

 

 

  

Regulation

46

 

 

  

Environmental Matters

52

 

 

 

Safety and Environmental Protection

54

 

Item 1A:

Risk Factors

55-61

 

Item 1B:

Unresolved Staff Comments

61

 

Item 3:

Legal Proceedings

61

 

Item 4:

Submission of Matters to a Vote of Security Holders

61

 

  

 

 

 

 

PART II

 

 

Item 5:

Market for Registrant’s Common Equity, Related Stockholder

 

 

 

Matters and Issuer Purchases of Equity Securities

62

 

Item 6:

Selected Financial Data

63-64

 

Item 7:

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

65-118

 

  

  

General

65

 

  

  

Critical Accounting Policies and Estimates

65

 

  

  

Consolidated Financial Results

70

 

  

  

Results Of Operations

72

 

  

  

Natural Gas Pipeline Company of America

73

 

 

 

Terasen Gas

75

 

 

 

Kinder Morgan Canada (Formerly Terasen Pipelines)

75

 

  

  

Power

77

 

 

 

Products Pipelines – KMP

78

 

 

 

Natural Gas Pipelines – KMP

85

 

 

 

CO2 – KMP

89

 

 

 

Terminals – KMP

94

 

  

  

TransColorado

100

 

  

  

Earnings from Our Investment in Kinder Morgan Energy Partners

100

 

  

  

Interest and Corporate Expenses, Net

101

 

  

  

Income Taxes – Continuing Operations

102

 

  

  

Income Taxes – Realization of Deferred Tax Assets

102

 

  

  

Discontinued Operations

102

 

  

  

Liquidity and Capital Resources

103

 

  

  

Investment in Kinder Morgan Energy Partners

112

 

  

  

Cash Flows

112

 

  

  

Litigation and Environmental Matters

115

 

  

  

Regulation

116

 

  

  

Recent Accounting Pronouncements

116

 

Item 7A:

Quantitative and Qualitative Disclosures About Market Risk

118-119

 

Item 8:

Financial Statements and Supplementary Data

120-238

 




3



KMI Form 10-K



KINDER MORGAN, INC. AND SUBSIDIARIES
CONTENTS (Continued)

Item 9:

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

239

 

Item 9A:

Controls and Procedures

239

 

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

239

 

 

Changes in Internal Control over Financial Reporting

239

 

Item 9B:

Other Information

 

239

 

  

PART III

 

 

Item 10:

Directors, Executive Officers and Corporate Governance

240-243

 

Item 11:

Executive Compensation

243-258

 

Item 12:

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

259-261

 

Item 13:

Certain Relationships and Related Transactions, and Director Independence

261-262

 

Item 14:

Principal Accounting Fees and Services

262-263

 

  

 

 

 

  

PART IV

 

 

Item 15:

Exhibits and Financial Statement Schedules

264-268

 

  

 

 

 

Signatures

269

 

  

 

 

 


Note:  Individual financial statements of the parent company are omitted pursuant to the provisions of Accounting Series Release No. 302.



4



KMI Form 10-K



PART I

Items 1. and 2.

Business and Properties.

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. (a Kansas corporation, incorporated on May 18, 1927, formerly known as K N Energy, Inc.) and its consolidated subsidiaries. All dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. To convert December 31, 2006 balances denominated in Canadian dollars to U.S. dollars, we used the December 31, 2006 Bank of Canada closing exchange rate of 0.8581 U.S. dollars per Canadian dollar. Unless otherwise indicated, all volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute and at 60 degrees Fahrenheit and, in most instances, are rounded to the nearest major multiple. In this report, the term “MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the term “TJ” means terajoule (one thousand gigajoules), the term “PJ” means petajoule (one million gigajoules), the term “bpd” means barrels per day and the terms “Dth” (dekatherms) and “MMBtus” mean million British Thermal Units (“Btus”). Natural gas liquids consist of ethane, propane, butane, iso-butane and natural gasoline. For the purpose of making Imperial to Metric conversions, 1 mile equals 1.609 kilometers and 1MMBtu equals 1.055 gigajoules. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.

(A) General Development of Business

We are one of the largest energy transportation and storage companies in North America. We own the general partner interest and a significant limited partner interest in Kinder Morgan Energy Partners, L.P. (“Kinder Morgan Energy Partners”), a publicly traded pipeline limited partnership. Due to our implementation of Emerging Issues Task Force (“EITF”) No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, we have included Kinder Morgan Energy Partners and its consolidated subsidiaries in our consolidated financial statements effective January 1, 2006. This means that the accounts, balances and results of operations of Kinder Morgan Energy Partners and its consolidated subsidiaries are now presented on a consolidated basis with ours and those of our other consolidated subsidiaries for financial reporting purposes, instead of equity method accounting as previously reported. See Note 1(B) of the accompanying Notes to Consolidated Financial Statements. We operate or own an interest in approximately 43,000 miles of pipelines and approximately 155 terminals. Our pipelines transport more than two million barrels per day of gasoline and other petroleum products and up to 10.5 billion cubic feet per day of natural gas. Our terminals handle over 80 million tons of coal and other dry-bulk materials annually and have a liquids storage capacity of almost 70 million barrels for petroleum products and chemicals. We own and operate retail natural gas distribution businesses serving approximately 905,000 customers in British Columbia. We are also the leading independent provider of carbon dioxide for enhanced oil recovery projects in the United States. Our common stock is traded on the New York Stock Exchange under the symbol “KMI.” Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

On October 7, 1999, we completed the acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and the sole stockholder of the general partner of Kinder Morgan Energy Partners. To effect that acquisition, we issued approximately 41.5 million shares of our common stock in exchange for all of the outstanding shares of Kinder Morgan (Delaware). Upon closing of the transaction, Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan (Delaware), was named our Chairman and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. As a result of that acquisition and certain subsequent transactions, we own the general partner of, and have a significant limited partner interest in, Kinder Morgan Energy Partners, one of the largest publicly traded pipeline limited partnerships in the United States in terms of market capitalization, and the owner and operator of the largest independent refined petroleum products pipeline system in the United States in terms of volumes delivered. Additional information concerning our investment in Kinder Morgan Energy Partners and its various businesses is contained in Note 2 of the accompanying Notes to Consolidated Financial Statements and in Kinder Morgan Energy Partners’ 2006 Annual Report on Form 10-K.

In May 2001, Kinder Morgan Management, LLC (“Kinder Morgan Management”), one of our indirect subsidiaries, issued and sold its limited liability shares in an underwritten initial public offering. The net proceeds from the offering were used by Kinder Morgan Management to buy i-units from Kinder Morgan Energy Partners for $991.9 million. Upon purchase of the i-units, Kinder Morgan Management became a limited partner in Kinder Morgan Energy Partners and was delegated by Kinder Morgan Energy Partners’ general partner, the responsibility to manage and control the business and affairs of Kinder Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy Partners’ limited partner interests that have been, and will be, issued only to Kinder Morgan Management. We have certain rights and obligations with respect to these securities.

In the initial public offering, we purchased 10% of the Kinder Morgan Management shares, with the balance purchased by the public. The equity interest in Kinder Morgan Management (which is consolidated in our financial statements) owned by the public is reflected as minority interest on our balance sheet. The earnings recorded by Kinder Morgan Management that



5



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



are attributed to its shares held by the public are reported as “minority interest” in our Consolidated Statements of Operations. Subsequent to the initial public offering by Kinder Morgan Management of its shares, our ownership interest in Kinder Morgan Management has changed because (i) we recognize our share of Kinder Morgan Management’s earnings, (ii) we record the receipt of distributions attributable to the Kinder Morgan Management shares that we own, (iii) Kinder Morgan Management has made additional sales of its shares (both through public and private offerings), (iv) pursuant to an option feature that was previously available to Kinder Morgan Management shareholders but no longer exists, we exchanged certain of the Kinder Morgan Energy Partners’ common units held by us for Kinder Morgan Management shares held by the public and (v) we sold some Kinder Morgan Management shares we owned in order to generate taxable gains to offset expiring tax loss carryforwards. At December 31, 2006, we owned 10.3 million Kinder Morgan Management shares representing 16.5% of Kinder Morgan Management’s total outstanding shares. Additional information concerning the business of, and our investment in and obligations to, Kinder Morgan Management is contained in Note 3 of the accompanying Notes to Consolidated Financial Statements and in Kinder Morgan Management’s 2006 Annual Report on Form 10-K.

On November 30, 2005, we completed the acquisition of Terasen Inc., referred to in this report as Terasen and, accordingly, Terasen’s results of operations are included in our consolidated results of operations beginning on that date. Terasen is an energy transportation and utility services provider headquartered in Burnaby, British Columbia, Canada. Terasen’s two core businesses are its natural gas distribution business and its petroleum pipeline business. Terasen Gas is the largest distributor of natural gas in British Columbia, serving approximately 905,000 customers at December 31, 2006. Terasen Pipelines, which we have renamed Kinder Morgan Canada, operates Trans Mountain Pipe Line, which extends from Edmonton to Vancouver and Washington State, and Corridor Pipeline, which operates between the Alberta oilsands and Edmonton. Both Trans Mountain Pipe Line and Corridor Pipeline are owned by Terasen. Kinder Morgan Canada also operates, and Terasen owns a one-third interest in, the Express System, which extends from Alberta to the U.S. Rocky Mountain region and Midwest.

On May 29, 2006, we announced that our board of directors had received a proposal from investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, to acquire all of our outstanding common stock for $100 per share in cash. The investors include Richard D. Kinder, other senior members of our management, co-founder Bill Morgan, current board members Fayez Sarofim and Mike Morgan, and affiliates of Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, and Riverstone Holdings LLC. Our board of directors formed a special committee composed entirely of independent directors to consider the proposal. On August 28, 2006, we entered into a definitive merger agreement under which the investors would acquire all of our outstanding common stock (except for shares held by certain stockholders and investors) for $107.50 per share in cash, without interest, and our board of directors, on the unanimous recommendation of the special committee, approved the agreement and recommended that our stockholders approve the merger.

Our stockholders voted to approve the proposed merger agreement on December 19, 2006. On January 25, 2007, we announced that we had received Hart-Scott-Rodino Antitrust Improvements Act clearance for the proposed acquisition. The Federal Trade Commission had challenged the participation of certain investors, but those investors reached a settlement with the FTC that clears the way for the acquisition to proceed. Currently, the only outstanding approvals are from certain state regulatory utility commissions. The California Public Utilities Commission issued a procedural schedule which could delay the closing of the transaction until the second quarter of 2007; however, we are working diligently with the CPUC to try to expedite the matter and are hopeful that the transaction can be closed in the first or second quarter of 2007. Upon closing of the transaction, our common stock will no longer be traded on the New York Stock Exchange.

Business Strategy

Our business strategy is to: (i) focus on fee-based energy transportation and storage assets that are core to the energy infrastructure of growing markets within North America, (ii) increase utilization of our existing assets while controlling costs, operating safely and employing environmentally sound operating practices, (iii) leverage economies of scale from incremental acquisitions and expansions of properties that fit within our strategy and are accretive to earnings and cash flow and (iv) maximize the benefits of our financial structure to create and return value to our stockholders as discussed following.

We intend to maintain a capital structure that provides flexibility and stability, while returning value to our shareholders through dividends and share repurchases. During 2006, we utilized cash generated from operations (including cash received from distributions attributable to our investment in Kinder Morgan Energy Partners) to pay common stock dividends, finance our capital expenditures program and repurchase our common shares. In recent periods, we have increased our common stock dividends in response to changes in income tax laws that have made dividends a more efficient way to return cash to our shareholders.

We expect to benefit from accretive acquisitions (primarily by Kinder Morgan Energy Partners). Kinder Morgan Energy Partners has a multi-year history of making accretive acquisitions, which benefit us through our limited and general partner



6



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



interests. This acquisition strategy is expected to continue, although we can provide no assurance that such acquisitions will occur in the future. In addition, we expect to benefit from expansion opportunities pursued both by Kinder Morgan Energy Partners and by us. Along with Sempra Pipelines & Storage, a unit of Sempra Energy, and ConocoPhillips, Kinder Morgan Energy Partners is developing the Rockies Express Pipeline, a new natural gas pipeline that when completed will link producing areas in the Rocky Mountain region to the upper Midwest and Eastern United States. The approximately $4.4 billion project will be placed in service in segments and is expected to be completed by June 2009, subject to regulatory approvals. The Rockies Express Pipeline will have the capability to transport 1.8 Bcf per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity. We expect to expand, within strict guidelines as to risk, rate of return and timing of cash flows, Kinder Morgan Canada’s (formerly Terasen Pipelines’) pipeline systems and NGPL’s pipeline system.

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

It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under “Risk Factors” elsewhere in this report, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

Recent Developments

·

Going Private Transaction
As discussed above, on December 19, 2006, our stockholders voted to approve a definitive merger agreement under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, would acquire all of our outstanding common stock for $107.50 per share in cash. The transaction is expected to be completed in the first or second quarter of 2007, subject to receipt of regulatory approvals, as well as the satisfaction of other customary closing conditions.

·

Sale of U.S. Retail Operations
In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented.

·

Sale of Terasen Gas Business Segment
On February 26, 2007, we entered into a definitive agreement to sell Terasen Inc. to Fortis Inc. (TSX: FTS), a Canada-based company with investments in regulated distribution utilities, for approximately $3.2 billion (C$3.7 billion) including cash and assumed debt. Terasen Inc.’s principal assets include Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. The transaction is subject to certain closing conditions and regulatory approvals and is expected to close in mid 2007.  This sale does not include assets of Kinder Morgan Canada.

·

Dividends
We increased our annual rate of cash dividends per share by $0.50 in the first quarter of 2006, reaching an annual rate of $3.50. This increase was principally in response to federal tax legislation enacted in 2003 and to increased cash flow.

·

NGPL Re-Contracting Transportation and Storage Capacity
In 2006, NGPL extended long-term firm transportation and storage contracts with some of its largest shippers, including Northern Illinois Gas Company (Nicor), The Peoples Gas Light and Coke Company, Centerpoint Energy Minnesota Gas, Interstate Power and Light Company, subsidiaries of Ameren Corporation, and Wisconsin Electric Power Co. Combined, the contracts represent approximately 0.49 million Dth per day of annual firm transportation service.

·

NGPL Storage Expansions
In the second quarter of 2006, NGPL placed into service a $38 million expansion of its Sayre storage field located in Oklahoma, which added 10 Bcf of storage service capacity, all of which is contracted for under long-term agreements. In August 2005, NGPL filed a certificate application with the Federal Energy Regulatory Commission (“FERC”) for an additional 10 Bcf expansion of its North Lansing storage facility located in east Texas, at a cost of $74 million. All of the capacity is contracted for under long-term agreements. The FERC order approving the project



7



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



was issued January 23, 2006. Service is anticipated to commence during the spring of 2007.

·

NGPL Amarillo-Gulf Coast Line Expansion
In the second quarter of 2006, NGPL placed into service its Amarillo-Gulf Coast cross-haul expansion. The $21 million project added 51,000 Dth per day of capacity and is fully subscribed under long-term contracts. In addition, NGPL added a new compressor station to Segment 17 of its Amarillo-Gulf Coast line that provides 140 MMcf per day of additional capacity. The $17 million project was placed in service January 6, 2007, and all of the additional capacity is fully contracted.

·

NGPL Louisiana Line Expansion
In October 2006, NGPL filed with the FERC seeking approval to expand its Louisiana Line by 200,000 Dth per day. This $66 million project is supported by five-year agreements that fully subscribe the additional capacity.

·

Kinder Morgan Illinois Pipeline
In September 2006, Kinder Morgan Illinois Pipeline filed with FERC seeking approval to acquire lease capacity on NGPL and build facilities to supply service for The Peoples Gas Light and Coke Co., who has signed a 10-year agreement for all the capacity. The $13.3 million project would have a capacity of 360,000 Dth per day.

·

Terasen Gas Pipeline Project
In June 2006, the BCUC approved an application from Terasen Gas Inc. to build a 50-kilometer natural gas pipeline from Squamish to Whistler. The estimated C$42 million project, which includes the cost of retrofitting utility customers’ gas-fired appliances from propane to natural gas use, will replace an aging propane system. Construction on this project is being integrated with and performed by the contractor performing the highway upgrades to Whistler in advance of the 2010 Winter Olympics. We expect full service to be available to Whistler by November 2008.

·

Kinder Morgan Canada Trans Mountain Pipeline Expansions
On November 10, 2005, Kinder Morgan Canada received approval from the National Energy Board (“NEB”) to increase the capacity of the Trans Mountain pipeline system from 225,000 barrels per day (“bpd”) to 260,000 bpd. The C$195 million expansion is designed to add 35,000 bpd of heavy crude oil capacity by building new and upgrading existing pump stations along the pipeline system between Edmonton, Alberta, and Burnaby, British Columbia. Construction began in the summer of 2006 and the expansion is expected to be in service by April 2007.

Kinder Morgan Canada filed a comprehensive environmental report with the Canadian Environmental Assessment Agency on November 15, 2005, and filed a complete NEB application for the Anchor Loop Project on February 17, 2006. The C$443 million project involves looping a 98-mile section of the existing Trans Mountain pipeline system between Hinton, Alberta, and Jackman, British Columbia, and the addition of three new pump stations. With construction of the Anchor Loop, the Trans Mountain system’s capacity will increase from 260,000 bpd to 300,000 bpd by the end of 2008. The public hearing of the application was held the week of August 8, 2006. On October 26, 2006, the NEB released its favorable decision on the application.

·

Kinder Morgan Canada Corridor Pipeline Expansion
An application for the Corridor pipeline expansion project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005, and approval was received in August 2006. The proposed C$1.8 billion expansion, as authorized and supported by shipper resolutions and the underlying firm service agreement, includes building a new 42-inch diameter diluent/bitumen (“dilbit”) pipeline, a new 20-inch diameter products pipeline, tankage and upgrading existing pump stations along the existing pipeline system from the Muskeg River Mine north of Fort McMurray to the Edmonton region. The Corridor pipeline expansion would add an initial 180,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. An expansion of the Corridor pipeline system has been completed in 2006 increasing the dilbit capacity to 278,000 bpd by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 460,000 bpd. Construction of the Corridor pipeline expansion began in November 2006.

·

Products Pipelines – KMP Pacific Operations Regulatory Matter
On March 7, 2006, Kinder Morgan Energy Partners’ Pacific operations filed a revised cost of service filing with the FERC in accordance with the FERC’s December 16, 2005 order addressing two cases: (i) the phase two initial decision, issued September 9, 2004, which would establish the basis for prospective rates and the calculation of reparations for complaining shippers with respect to the Pacific operations’ West Line and East Line pipelines, and (ii) certain cost of service issues remanded to the FERC by the United States Court of Appeals for the District of Columbia Circuit, referred to in this report as D.C. Circuit, in its July 2004 BP West Coast Products v. FERC opinion, including the level of income tax allowance that the Pacific operations is entitled to include in its interstate rates. The December 16, 2005 order did not address the FERC’s March 2004 phase one rulings on the grandfathered



8



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



state of the Pacific operations’ rates that are currently pending on appeal before the D.C. Circuit.

On April 28, 2006, the FERC issued an order accepting Kinder Morgan Energy Partners’ Pacific operations’ compliance filing and revised tariffs, which lowered its West Line and East Line rates in conformity with previous FERC orders, and these lower tariff rates became effective May 1, 2006. Further, Kinder Morgan Energy Partners was required to calculate estimated reparations for complaining shippers consistent with the December 16, 2005 FERC order, and various parties have submitted comments to the FERC challenging aspects of the costs of service and tariff rates reflected in the compliance filings. The FERC indicated that a subsequent order would address the issues raised in these comments. In December 2005, Kinder Morgan Energy Partners recognized a $105.0 million non-cash expense attributable to an increase in its reserves related to its rate case liability; however, we are not able to predict with certainty the final outcome of the pending FERC proceedings, or whether we can reach a settlement with some or all of the complainants. For additional information, see Note 19 to our consolidated financial statements.

·

Products Pipelines – KMP Watson Station Regulatory Settlement
On May 17, 2006, Kinder Morgan Energy Partners entered into a settlement agreement and filed an offer of settlement with the FERC in response to certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at the Pacific operations’ Watson Station, located in Carson, California. On August 2, 2006, the FERC approved the settlement without modification and directed that it be implemented. Pursuant to the settlement, Kinder Morgan Energy Partners filed a new tariff, which took effect September 1, 2006, lowering the Pacific Operations’ going-forward rate, and Kinder Morgan Energy Partners also paid refunds to all shippers for the period April 1, 1999 through August 31, 2006.

On September 28, 2006, Kinder Morgan Energy Partners filed a refund report with the FERC, setting forth the refunds that had been paid and describing how the refund calculations were made. On December 5, 2006, the FERC approved the refund report with respect to all shippers except ExxonMobil, and it remanded the ExxonMobil refund issue to an administrative law judge for a determination as to whether additional refunds were due. On January 16, 2007, Kinder Morgan Energy Partners and ExxonMobil informed the presiding judge that they had reached a settlement in principle regarding the ExxonMobil refund issue, and in February 2007, Kinder Morgan Energy Partners and ExxonMobil reached agreement regarding ExxonMobil’s protest of the refund report, and the protest was withdrawn. As of December 31, 2006, Kinder Morgan Energy Partners made aggregate payments pursuant to the agreement, including accrued interest, of $19.1 million.

·

Products Pipelines – KMP Pacific Operations East Line Expansion
On June 1, 2006, Kinder Morgan Energy Partners announced that it had completed and fully placed into service a $210 million expansion of the Pacific operations’ East Line pipeline segment. The completion of the project included the construction of a new pump station, a 490,000 barrel tank facility near El Paso, Texas, and upgrades to existing stations and terminals between El Paso and Phoenix, Arizona. Initially proposed in October 2002, the expansion also includes the replacement of 160 miles of 8-inch diameter pipe between El Paso and Tucson, Arizona, and 84 miles of 8-inch diameter pipe between Tucson and Phoenix with new state-of-the-art 12-inch and 16-inch diameter pipe, respectively. Kinder Morgan Energy Partners announced the completion of the pipeline portion of the project on April 19, 2006, and new transportation tariffs designed to earn a return on its construction costs went into effect June 1, 2006.

In addition, Kinder Morgan Energy Partners continues working on its second East Line expansion project, which it announced on August 4, 2005. This second expansion consists of replacing approximately 140 miles of 12-inch diameter pipe between El Paso and Tucson with 16-inch diameter pipe, constructing additional pump stations, and adding new storage tanks at Tucson. The project is expected to cost approximately $145 million. Kinder Morgan Energy Partners is currently working on engineering design and obtaining necessary pipeline permits, and construction is expected to begin in May 2007. The project, scheduled for completion in December 2007, will increase East Line capacity by another 8% and will provide the platform for further incremental expansions through horsepower additions to the system.

·

Products Pipelines – KMP CALNEV Pipeline System Expansion
On October 19, 2006, Kinder Morgan Energy Partners announced the third of three investments in its CALNEV refined petroleum products pipeline system. CALNEV is a 550-mile pipeline that currently transports approximately 140,000 barrels of refined products per day of gasoline, diesel fuel and jet fuel from the Los Angeles, California area to the Las Vegas, Nevada market through parallel 14-inch and 8-inch diameter pipelines. Combined, the $413 million in capital improvements will upgrade and expand pipeline capacity and help provide sufficient fuel supply to the Las Vegas, Nevada market for the next several years. The investments include the following:

·

the first project, estimated to cost approximately $10 million, involves pipeline expansions that will



9



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



increase current transportation capacity by 3,200 barrels per day (2.2%), as well as the construction of two new 80,000 barrel storage tanks at the Las Vegas terminal;

·

the second project, expected to cost approximately $15 million, includes the installation of new and upgraded pumping equipment and piping at the Colton, California terminal, a new booster station with two pumps at Cajon, California, and piping upgrades at the Las Vegas terminal; and

·

the third project, expected to cost approximately $388 million, includes construction of a new 16-inch diameter pipeline that will further expand the system and which would increase system capacity to approximately 200,000 barrels per day upon completion. Capacity could be increased as necessary to over 300,000 barrels per day with the addition of pump stations. The new 16-inch diameter pipeline will parallel existing utility corridors between Colton and Las Vegas in order to minimize environmental impacts. It will transport gasoline and diesel, as well as military jet fuel for Nellis Air Force Base, which is located eight miles northeast of downtown Las Vegas. The existing 14-inch diameter pipeline will be dedicated to commercial jet fuel service for McCarran International Airport in Las Vegas and for any future commercial airports planned for the Las Vegas market. The 8-inch diameter pipeline that currently serves McCarran would be purged and held for future service. The expansion is subject to environmental permitting, rights-of-way acquisition and the receipt of approvals from the FERC authorizing rates that are economic to CALNEV. Start-up of the new pipeline is scheduled for early 2010.

In addition, Kinder Morgan Energy Partners is currently working with its customers to determine interest in the construction of a new refined products distribution terminal to be located south of Henderson, Nevada.

·

Products Pipelines – KMP Cochin Pipeline System Ownership Interest To Increase to 100%
On January 15, 2007, Kinder Morgan Energy Partners announced that it had entered into an agreement with affiliates of BP to increase Kinder Morgan Energy Partners’ ownership interest in the Cochin pipeline system to 100%. Kinder Morgan Energy Partners purchased its original undivided 32.5% ownership interest in the Cochin pipeline system in November 2000, and currently, Kinder Morgan Energy Partners owns a 49.8% ownership interest. BP Canada Energy Company, an affiliate of BP, owns the remaining 50.2% ownership interest and is the operator of the pipeline. The agreement is subject to due diligence, regulatory clearance and other customary closing conditions. The transaction is expected to close in the first quarter of 2007, and upon closing, Kinder Morgan Energy Partners will become the operator of the pipeline.

·

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

On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that now consists of two segments: (i) a 136-mile, 36-inch diameter pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the Wamsutter Hub in Sweetwater County, Wyoming and (ii) a 191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in Weld County, Colorado, where it will ultimately connect with the Rockies Express Pipeline, an interstate natural gas pipeline that is currently being developed by Rockies Express Pipeline LLC. In the first quarter of 2006, EnCana Corporation completed construction of the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and interim service began on that portion of the pipeline on February 24, 2006. In February 2007, Kinder Morgan Energy Partners completed construction of the second pipeline segment that extends from the Wamsutter Hub to the Cheyenne Hub and service began on the first two pipeline segments on February 14, 2007.

However, our operating revenues and our operating expenses were not impacted during the construction or interim service periods due to the fact that regulatory accounting provisions require capitalization of revenues and expenses until the second segment of the project was completed and in-service.

In April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline LLC. Going forward, the entire pipeline system (the two Entrega segments described above and the two Rockies Express segments that are currently being developed and described below) will be known as the Rockies Express Pipeline.

On May 31, 2006, Rockies Express Pipeline LLC filed an application with the FERC for authorization to construct



10



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



and operate certain facilities comprising its proposed Rockies Express-West project. This project is the first planned eastward extension of the certificated Rockies Express segments, described above. The Rockies Express-West project will be comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment extension will have capacity to transport up to 1.5 billion cubic feet per day of natural gas across the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub.

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

On September 21, 2006, the FERC issued a favorable preliminary determination on all non-environmental issues of the Rockies Express-West project, approving Rockies Express’ application (i) to construct and operate the 713 miles of new natural gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity from Questar Overthrust Pipeline Company, which will extend the Rockies Express system 140 miles west from Wamsutter to the Opal Hub in Wyoming. Pending completion of the FERC environmental review and the issuance of a certificate, the Rockies Express-West project is expected to begin service in January 2008.

The final segment of the Rockies Express Pipeline consists of an approximate 635-mile pipeline segment that will extend from eastern Missouri to the Clarington Hub in eastern Ohio. Rockies Express will file a separate application in the future for this proposed Rockies Express-East project. In June 2006, Kinder Morgan Energy Partners made the National Environmental Policy Act pre-filing for Rockies Express-East with the FERC. This project is expected to begin interim service as early as December 31, 2008, and to be fully completed by June 2009. When fully completed, the combined 1,675-mile Rockies Express Pipeline system will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.4 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity.

·

Natural Gas Pipelines – KMP Sale of Douglas Gathering System and Painter Unit Fractionation Facility
Effective April 1, 2006, Kinder Morgan Energy Partners sold its Douglas natural gas gathering system and its Painter Unit fractionation facility to Momentum Energy Group, LLC for approximately $42.5 million in cash. Our investment in net assets, including all transaction related accruals, was approximately $24.5 million, most of which represented property, plant and equipment, and we recognized approximately $18.0 million of gain on the sale of these net assets.

Additionally, with regard to the natural gas operating activities of our Douglas gathering system, we utilized certain derivative financial contracts to offset (hedge) our exposure to fluctuating expected future cash flows caused by periodic changes in the price of natural gas and natural gas liquids. According to the provisions of current accounting principles, when an asset generating a hedged transaction is disposed of prior to the occurrence of the transaction, the net cumulative gain or loss previously recognized in equity should be transferred to net income in the current period. Accordingly, we reclassified a net loss of $2.9 million from “Accumulated other comprehensive loss” into net income on those derivative contracts that effectively hedged uncertain future cash flows associated with forecasted Douglas gathering transactions. We included the net amount of the gain, $15.1 million, within the caption “Other expense (income)” in our accompanying consolidated statement of income for the year ended December 31, 2006.

·

Natural Gas Pipelines – KMP Long-term Transportation and Storage Services Contract
On April 18, 2006, Kinder Morgan Energy Partners announced that its Texas intrastate natural gas pipeline group had entered into a long-term agreement with CenterPoint Energy Resources Corp. to provide the natural gas utility with firm transportation and storage services. Under the terms of the agreement, CenterPoint has contracted for one billion cubic feet per day of transportation capacity and 16 billion cubic feet of storage capacity, effective April 1, 2007. CenterPoint owns and operates the largest local natural gas distribution company in Houston, Texas, and the agreement helps ensure the Houston metropolitan area has access to reliable and diverse supplies of natural gas in order to meet the growing demand.



11



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



·

Natural Gas Pipelines – KMP North Dayton, Texas Storage Expansion
On June 8, 2006, Kinder Morgan Energy Partners announced an approximate $76 million expansion project that will significantly increase capacity at its North Dayton, Texas natural gas storage facility. The project involves the development of a new underground cavern that will add an estimated 5.5 billion cubic feet of incremental working natural gas storage capacity. Currently, two existing storage caverns at the facility provide approximately 4.2 billion cubic feet of working gas capacity. The North Dayton natural gas storage facility is connected to Kinder Morgan Energy Partners’ Texas Intrastate natural gas pipeline system, and the expansion will greatly enhance storage options for natural gas coming from new and growing supply areas located in East Texas and from liquefied natural gas along the Texas Gulf Coast. Project costs are now anticipated to range from $76 million to $82 million, and the additional capacity is expected to be available in mid-2009.

·

Natural Gas Pipelines – KMP TransColorado’s ”Blanco-Meeker Expansion Project”
On June 23, 2006, TransColorado Gas Transmission Company filed an application for authorization with the FERC to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” Upon implementation, this approximately $58 million project will facilitate the transportation of up to approximately 250 million cubic feet per day of natural gas northbound from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located at the Meeker Hub in Rio Blanco County, Colorado. The expansion is expected to begin service on January 1, 2008, subject to receipt of all necessary regulatory approvals.

·

Natural Gas Pipelines – KMP Kinder Morgan Louisiana Pipeline
On September 8, 2006, Kinder Morgan Energy Partners filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline. The project is expected to cost approximately $500 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. Various water and environmental surveys have been completed and Kinder Morgan Energy Partners procured long-lead items, such as line pipe and mainline block valves. Kinder Morgan Energy Partners is currently finalizing interconnect agreements, preparing detailed designs of the facilities and acquiring necessary rights-of-way.

The Kinder Morgan Louisiana Pipeline will consist of two segments: (i) a 132-mile, 42-inch diameter pipeline with firm capacity of approximately 2.0 billion cubic feet per day of natural gas that will extend from the Sabine Pass terminal to a point of interconnection with an existing Columbia Gulf Transmission line in Evangeline Parish, Louisiana, including an offshoot consisting of approximately 2.3 miles of 24-inch diameter pipeline with firm peak day capacity of approximately 300 million cubic feet per day extending away from the 42-inch diameter line to the existing Florida Gas Transmission Company compressor station in Acadia Parish, Louisiana.; and (ii) a 1-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2 billion cubic feet per day that will extend from the Sabine Pass terminal and connect to Natural Gas Pipeline Company of America’s natural gas pipeline. In addition, in exchange for shipper commitments to the project, Kinder Morgan Energy Partners has granted options to acquire equity in the project, which, if fully exercised, could result in Kinder Morgan Energy Partners owning a minimum interest of 80% after the project is completed. The 132-mile pipeline segment is expected to be in service in the second quarter of 2009, and the 1-mile segment is expected to be in service in the third quarter of 2008.

On January 26, 2007, the FERC issued a draft Environmental Impact Statement (“EIS”) which addresses the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The draft EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the proposed project would have limited adverse environmental impact. The public will have until March 19, 2007 to file comments on the draft, which will be taken into account in the preparation of the final EIS.

·

Natural Gas Pipelines – KMP Midcontinent Express Pipeline
On December 13, 2006, Kinder Morgan Energy Partners announced that it had entered into a joint development of the Midcontinent Express Pipeline with Energy Transfer Partners, L.P., and the start of a binding open season for the pipeline’s firm natural gas transportation capacity. The approximate $1.25 billion interstate natural gas pipeline project will consist of an approximate 500-mile pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Williams’ Transco natural gas pipeline system in Butler, Alabama. Kinder Morgan Energy Partners will own 50% of the equity in the project and Energy Transfer Partners, L.P. will own the remaining 50% interest. The new pipeline will also connect to Natural Gas Pipeline Company of America’s natural gas pipeline and to Energy Transfer Partners’ previously announced 135-mile, 36-inch diameter natural gas pipeline, which extends from the Barnett Shale natural gas producing area in North Texas to an interconnect with its 30-inch diameter Texoma Pipeline near Paris, Texas.

The Midcontinent Express Pipeline will have an initial transportation capacity of 1.4 billion cubic feet per day of



12



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



natural gas, and pending necessary regulatory approvals, is expected to be in service by February 2009. The pipeline has prearranged binding commitments from multiple shippers for approximately 850,000 cubic feet per day, including a binding commitment for 500,000 cubic feet per day from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation. Additionally, in order to provide a seamless transportation path from various locations in Oklahoma, the Midcontinent Express Pipeline has also executed a firm capacity lease agreement for up to 500,000 cubic feet per day with Enogex, Inc., an Oklahoma-based intrastate natural gas gathering and pipeline company that is wholly owned by OGE Energy Corp.

·

CO2 – KMP Oil and Gas Property Acquisition
On April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an aggregate consideration of approximately $63.9 million, consisting of $60.3 million in cash and $3.6 million in assumed liabilities.  The acquisition was effective March 1, 2006. However, in the second and third quarters of 2006, Kinder Morgan Energy Partners divested certain acquired properties that were not considered candidates for carbon dioxide enhanced oil recovery, thus reducing its total investment. Kinder Morgan Energy Partners received proceeds of approximately $27.1 million from the sale of these properties. The acquired properties are primarily located in the Permian Basin area of West Texas and New Mexico, produce approximately 430 barrels of oil equivalent per day, and include some fields with potential for enhanced oil recovery development near Kinder Morgan Energy Partners’ current carbon dioxide operations.

·

CO2 – KMP Carbon Dioxide Expansion Projects
On January 17, 2007, Kinder Morgan Energy Partners announced that its CO2 business segment will invest approximately $120 million to further expand its operations and enable it to meet the increased demand for carbon dioxide in the Permian Basin. The expansion activities will take place in southwest Colorado and will include developing a new carbon dioxide source field and adding infrastructure at both the McElmo Dome Unit and the Cortez Pipeline. Specifically, the expansion will involve developing a new carbon dioxide source field in Dolores County, Colorado (named the Doe Canyon Deep Unit), adding eight carbon dioxide production wells at the McElmo Dome Unit, increasing transportation capacity on the Cortez Pipeline, and constructing a new pipeline that will connect the Cortez Pipeline to the new Doe Canyon Deep Unit. Initial construction activities have begun with expected in-service dates commencing in early 2008. The entire expansion is expected to be completed by the middle of 2008.

·

Terminals – KMP East Coast Liquids Terminal Expansion
On January 12, 2006, Kinder Morgan Energy Partners announced a major expansion project that will provide additional infrastructure to help meet the growing need for terminal services in key markets along the East Coast. The investment of approximately $45 million includes the construction of new liquids storage tanks at Kinder Morgan Energy Partners’ Perth Amboy, New Jersey liquids terminal located along the Arthur Kill River in the New York Harbor area. The Perth Amboy expansion involves the construction of nine new storage tanks with a capacity of 1.4 million barrels for gasoline, diesel and jet fuel. The expansion was driven by continued strong demand for refined products in the Northeast, much of which is being met by imported fuel arriving via the New York Harbor. The new tanks were expected to be in service beginning in the first quarter of 2007, however, due to inconsistencies in the soils underneath these tanks, we now estimate that the tank foundations will cost significantly more than originally budgeted, bringing the total investment to approximately $56 million and delaying the in-service date to the third quarter of 2007.

·

Terminals – KMP Bulk Terminal Expansion
On March 9, 2006, Kinder Morgan Energy Partners announced that it has entered into a long-term agreement with Drummond Coal Sales, Inc. that will support a $70 million expansion of Kinder Morgan Energy Partners’ Pier IX bulk terminal located in Newport News, Virginia. The agreement has a term that can be extended for up to 30 years. The project includes the construction of a new ship dock and the installation of additional equipment; it is expected to increase throughput at the terminal by approximately 30% and will allow the terminal to begin receiving shipments of imported coal. The expansion is expected to be completed in the first quarter of 2008. Upon completion, the terminal will have an import capacity of up to 9 million tons annually. Currently, the Pier IX terminal can store approximately 1.4 million tons of coal and 30,000 tons of cement on its 30-acre storage site.

·

Terminals – KMP Terminal Acquisition
In April 2006, Kinder Morgan Energy Partners acquired terminal assets and operations from A&L Trucking, L.P. and U.S. Development Group in three separate transactions for an aggregate consideration of approximately $61.9 million, consisting of $61.6 million in cash and $0.3 million in assumed liabilities. The first transaction included the acquisition of equipment and infrastructure for the storing and loading of bulk steel at a 30-acre site along the Houston Ship Channel leased through the Port of Houston. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal offers a variety of loading, storage and staging services for up to 900 cars at a time, and complements Kinder Morgan Energy Partners’



13



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



existing Texas petroleum coke terminal operations by providing bulk product customers with rail transportation options. Thirdly, Kinder Morgan Energy Partners acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal has the capability to receive and offload up to 100 railcars within a 24-hour period, and serves approximately 80% of the Southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity.

·

Terminals – KMP Construction of Crude Oil Tank Farm in Edmonton, Alberta
On June 21, 2006, Kinder Morgan Energy Partners announced that it, through its Kinder Morgan Terminals Canada, ULC subsidiary, began construction on a new $115 million crude oil tank farm located in Edmonton, Alberta, Canada, located slightly north of Kinder Morgan Canada’s Trans Mountain Pipeline crude oil storage facility. In addition, Kinder Morgan Energy Partners entered into long-term contracts with customers for all of the available capacity at the facility, with options to extend the agreements beyond the original terms. Situated on approximately 24 acres, the new storage facility will have nine tanks with a combined storage capacity of approximately 2.2 million barrels for crude oil. Service is expected to begin in the fourth quarter of 2007, and when completed, the tank farm will serve as a premier blending and storage hub for Canadian crude oil. The tank farm will have access to more than 20 incoming pipelines and several major outbound systems, including a connection with Kinder Morgan Canada’s 710-mile Trans Mountain Pipeline system, which currently transports up to 225,000 barrels per day of heavy crude oil and refined products from Edmonton to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State.

·

Terminals – KMP Pasadena and Galena Park, Texas Liquids Terminal Expansions
On September 11, 2006, Kinder Morgan Energy Partners announced major expansions at its Pasadena and Galena Park, Texas liquids terminal facilities located on the Houston Ship Channel. The expansions will provide additional infrastructure to help meet the growing need for refined petroleum products storage capacity along the Gulf Coast. The investment of approximately $195 million will include the construction of the following: (i) new storage tanks at both the Pasadena and Galena Park terminals; (ii) an additional cross-channel pipeline to increase the connectivity between the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional loading bay at the fully automated truck loading rack located at the 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.

·

Terminals – KMP Transload Services, LLC Acquisition
Effective November 20, 2006, Kinder Morgan Energy Partners acquired all of the membership interests of Transload Services, LLC for an aggregate consideration of approximately $16.8 million, consisting of $15.4 million in cash, an obligation to pay $0.9 million currently held as security for the collection of certain accounts receivable and for the perfection of certain real property title rights, and $0.5 million of assumed liabilities. Transload Services, LLC is a leading provider of innovative, high quality material handling and steel processing services, operating 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States. Its operations include transloading services, steel fabricating and processing, warehousing and distribution, and project staging. The combined operations include over 92 acres of outside storage and 445,000 square feet of covered storage that offers customers environmentally controlled warehouses with indoor rail and truck loading facilities for handling temperature and humidity sensitive products.

·

Terminals – KMP Devco USA L.L.C. Acquisition
Effective December 1, 2006, Kinder Morgan Energy Partners acquired all of the membership interests in Devco USA L.L.C. for an aggregate consideration of approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in common units, and $0.9 million of assumed liabilities. The primary asset acquired was a technology-based identifiable intangible asset—a proprietary process that transforms molten sulfur into premium solid formed pellets that are environmentally friendly, easy to handle and store, and safe to transport. The process was developed internally by Devco’s engineers and employees. Devco, a Tulsa, Oklahoma-based company, has more than 20 years of sulfur handling expertise and we believe the acquisition and subsequent application of this acquired technology complements Kinder Morgan Energy Partners’ existing dry-bulk terminal operations.

·

Kinder Morgan Energy Partners Public Offering
In August 2006, Kinder Morgan Energy Partners completed a public offering of 5,750,000 of its common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $44.80 per unit, less commissions and underwriting expenses. Kinder Morgan Energy Partners received net proceeds of $248.0 million for the issuance of these 5,750,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program.



14



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



·

Kinder Morgan Energy Partners Credit Facility Changes
Effective August 28, 2006, Kinder Morgan Energy Partners terminated its $250 million unsecured nine-month credit facility due November 21, 2006, and increased its five-year unsecured revolving credit facility from a total commitment of $1.6 billion to $1.85 billion. The five-year credit facility remains due August 18, 2010; however, the facility can now be amended to allow for borrowings up to $2.1 billion. There were no borrowings under the five-year credit facility as of December 31, 2006. The credit facility primarily serves as a backup to Kinder Morgan Energy Partners’ commercial paper program, which had $1,098.2 million outstanding as of December 31, 2006.

·

Kinder Morgan Energy Partners Cash Distribution Expectations for 2007
On December 14, 2006, Kinder Morgan Energy Partners announced that it expects to declare cash distributions of $3.44 per unit for 2007, an almost 6% increase over cash distributions of $3.26 per unit for 2006. This expectation includes contributions from assets owned by Kinder Morgan Energy Partners as of the announcement date and does not include any potential benefits from unidentified acquisitions. We expect Kinder Morgan Energy Partners’ growth to accelerate in the second half of 2007, and we anticipate that Kinder Morgan Energy Partners’ fourth quarter 2007 distribution per unit will be approximately 10% higher than its cash distribution per unit of $0.83 for the fourth quarter of 2006. Furthermore, while we expect that we will continue to be able to grow Kinder Morgan Energy Partners’ distribution per unit at about 8% per year over the long-term, the increase in 2008 is expected to be greater than 8%, due mainly to the anticipated in-service date of January 2008 for the western portion of the Rockies Express Pipeline.

·

Kinder Morgan Energy Partners 2006 Capital Expenditures
During 2006, Kinder Morgan Energy Partners spent $1,058.3 million for additions to property, plant and equipment, including both expansion and maintenance projects. Capital expenditures included the following:

·

$307.7 million in the Terminals – KMP segment, largely related to expanding the petroleum products storage capacity at liquids terminal facilities, including the construction of additional liquids storage tanks at facilities on the Houston Ship Channel, and to various expansion projects and improvements undertaken at multiple bulk terminal facilities;

·

$283.0 million in the CO2 – KMP 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;

·

$271.6 million in the Natural Gas Pipelines – KMP segment, mostly related to the inclusion of the capital expenditures of Rockies Express Pipeline LLC during the six-month period we included its results in our consolidated financial statements, as well as various expansion and improvement projects on the Texas Intrastate natural gas pipeline systems, including the development of additional natural gas storage capacity at the natural gas storage facilities located at Markham and Dayton, Texas; and

·

$196.0 million in the Products Pipelines – KMP segment, mostly related to the continued expansion work on the Pacific operations’ East Line products pipeline, the construction of an additional refined products line on the CALNEV Pipeline in order to increase delivery service to the growing Las Vegas, Nevada market, and to the combined expansion projects at the 24 refined products terminals included within the Southeast terminal operations.

·

Kinder Morgan Energy Partners Debt Offerings On January 30, 2007, Kinder Morgan Energy Partners completed a public offering of senior notes. Kinder Morgan Energy Partners 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. Kinder Morgan Energy Partners received proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $992.8 million, and used the proceeds to reduce the borrowings under its commercial paper program.

(B) Financial Information about Segments

Note 17 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments.

(C) Narrative Description of Business

Overview

We are an energy infrastructure provider. Our principal business segments are: (1) Natural Gas Pipeline Company of America and certain affiliates, referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural



15



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



gas pipeline and storage system; (2) Kinder Morgan Canada, a refined products and crude oil transportation pipeline business; (3) Terasen Gas, a natural gas distribution business involved in the transmission and distribution of natural gas and propane for residential, commercial and industrial customers in British Columbia; (4) Power, a business that owns and operates natural gas-fired electric generation facilities; (5) Products Pipelines – KMP, the ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; (6) Natural Gas Pipelines – KMP, the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (7) CO2 – KMP, the production, transportation and marketing of carbon dioxide (“CO2”) to oil fields that use CO2 to increase production of oil plus ownership interests in and/or operation of oil fields in West Texas plus the ownership and operation of a crude oil pipeline system in West Texas and (8) Terminals – KMP, the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the United States. In August 2006, we reached an agreement to sell our Kinder Morgan Retail segment. Accordingly, the activities and assets related to that segment are presented as discontinued items in the accompanying consolidated financial statements. In November 2004, we contributed TransColorado Gas Transmission Company to Kinder Morgan Energy Partners for total consideration of $275 million, consisting of approximately $210 million in cash and 1.4 million Kinder Morgan Energy Partners common units. TransColorado’s segment earnings of $20.3 million in 2004 prior to its contribution represented approximately 2% of our total 2004 segment earnings plus earnings attributable to our investment in Kinder Morgan Energy Partners, and approximately 2% of our 2004 income from continuing operations before interest and income taxes. In 1999, we discontinued our wholesale natural gas marketing, non-energy retail marketing services and natural gas gathering and processing businesses. Notes 5 and 17 of the accompanying Notes to Consolidated Financial Statements contain additional information on asset sales and our business segments. As discussed following, certain of our operations are regulated by various federal and state entities.

Natural gas transportation, storage and retail sales accounted for approximately 92%, 93% and 92% of our consolidated revenues in 2006, 2005 and 2004, respectively. During 2006, 2005 and 2004, we did not have revenues from any single customer that exceeded 10% of our consolidated operating revenues. Our equity in the earnings of Kinder Morgan Energy Partners (before reduction for the minority interest in Kinder Morgan Management) constituted approximately 54% and 61% of our income from continuing operations before interest and income taxes in 2005 and 2004, respectively. The following table gives our segment earnings, our earnings attributable to our investment in Kinder Morgan Energy Partners (net of pre-tax minority interest) and the percent of the combined total each represents, for each of the last two years.

 

Year Ended December 31,

 

2006

 

2005

 

Amount

 

 

% of Total

 

Amount

 

 

% of Total

 

(Dollars in millions)

Net Pre-tax Impact of Kinder Morgan Energy Partners1, 2

$

582.9

 

 

37.95

%

 

 

$

534.8

 

 

 

51.06

%

 

Segment Earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGPL

 

499.0

 

 

32.49

%

 

 

 

435.2

 

 

 

41.55

%

 

Kinder Morgan Canada

 

119.9

 

 

7.81

%

 

 

 

12.5

 

 

 

1.20

%

 

Terasen Gas

 

312.9

 

 

20.37

%

 

 

 

45.2

 

 

 

4.31

%

 

Power

 

21.1

 

 

1.38

%

 

 

 

19.7

 

 

 

1.88

%

 

Total

$

1,535.8

 

 

100.00

%

 

 

$

1,047.4

 

 

 

100.00

%

 


1

For 2006, Products Pipelines – KMP, Natural Gas Pipelines – KMP, CO2 – KMP, and Terminals – KMP represented approximately 25.0%, 29.3%, 24.9% and 20.8%, respectively, of Kinder Morgan Energy Partners’ segment earnings before depreciation, depletion and amortization.

2

Represents Kinder Morgan, Inc.’s general partner incentive and earnings from its ownership of limited partner interests in Kinder Morgan Energy Partners, net of associated minority interests.

Natural Gas Pipeline Company of America

During 2006, NGPL’s segment earnings of $499 million represented approximately 32% of total segment earnings plus net pre-tax impact of Kinder Morgan Energy Partners and approximately 28% of our income from continuing operations before interest, income taxes and the impairment of goodwill on our Terasen Gas segment. Through NGPL, we own and operate approximately 9,700 miles of interstate natural gas pipelines, storage fields, field system lines and related facilities, consisting primarily of two major interconnected natural gas transmission pipelines terminating in the Chicago, Illinois metropolitan area. The system is powered by 56 compressor stations in mainline and storage service having an aggregate of approximately 1.0 million horsepower. NGPL’s system has 813 points of interconnection with 34 interstate pipelines, 34 intrastate pipelines, 38 local distribution companies, 32 end users including power plants, and a number of gas producers, thereby providing significant flexibility in the receipt and delivery of natural gas. NGPL’s Amarillo Line originates in the



16



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



West Texas and New Mexico producing areas and is comprised of approximately 4,400 miles of mainline and various small-diameter pipelines. Its other major pipeline, the Gulf Coast Line, originates in the Gulf Coast areas of Texas and Louisiana and consists of approximately 4,100 miles of mainline and various small-diameter pipelines. These two main pipelines are connected at points in Texas and Oklahoma by NGPL’s approximately 800-mile Amarillo/Gulf Coast pipeline. In addition, NGPL owns a 50% equity interest in and operates Horizon Pipeline Company, L.L.C., a joint venture with Nicor-Horizon, a subsidiary of Nicor, Inc. This joint venture owns a natural gas pipeline in northern Illinois with a capacity of 380 MMcf per day.

NGPL provides transportation and storage services to third-party natural gas distribution utilities, marketers, producers, industrial end users and other shippers. Pursuant to transportation agreements and FERC tariff provisions, NGPL offers its customers firm and interruptible transportation, storage and no-notice services, and interruptible park and loan services. Under NGPL’s tariffs, firm transportation customers pay reservation charges each month plus a commodity charge based on actual volumes transported, including a fuel charge collected in kind. Interruptible transportation customers pay a commodity charge based upon actual volumes transported. Reservation and commodity charges are both based upon geographical location and time of year. Under firm no-notice service, customers pay a reservation charge for the right to have up to a specified volume of natural gas delivered but, unlike with firm transportation service, are able to meet their peaking requirements without making specific nominations. NGPL has the authority to discount its rates and to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure. NGPL’s revenues have historically been somewhat higher in the first and fourth quarters of the calendar year, reflecting higher system utilization during the colder months. During the winter months, NGPL collects higher transportation commodity revenue, higher interruptible transportation revenue, winter-only capacity revenue and higher rates on certain contracts.

NGPL’s principal delivery market area encompasses the states of Illinois, Indiana and Iowa and secondary markets in portions of Wisconsin, Nebraska, Kansas, Missouri and Arkansas. NGPL is the largest transporter of natural gas to the Chicago market, and we believe that its transportation rates are very competitive in the region. In 2006, NGPL delivered an average of 1.82 trillion Btus per day of natural gas to this market. Given its strategic location at the center of the North American natural gas pipeline grid, we believe that Chicago is likely to continue to be a major natural gas trading hub for growing markets in the Midwest and Northeast.

Substantially all of NGPL’s pipeline capacity is committed under firm transportation contracts ranging from one to five years. Approximately 63% of the total transportation volumes committed under NGPL’s long-term firm transportation contracts as of February 13, 2007 had remaining terms of less than three years. NGPL continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts, and was very successful in doing so during 2006 as discussed under “Recent Developments” elsewhere in this report. Nicor Gas Company, Peoples Gas Light and Coke Company, and Northern Indiana Public Service Company (NIPSCO) are NGPL’s three largest customers in terms of operating revenues from tariff services. During 2006, approximately 50% of NGPL’s operating revenues from tariff services were attributable to its eight largest customers. Contracts representing approximately 6.3% of NGPL’s total long-haul, contracted firm transport capacity as of January 31, 2007 are scheduled to expire during 2007.

NGPL is one of the nation’s largest natural gas storage operators with approximately 600 Bcf of total natural gas storage capacity, approximately 250 Bcf of working gas capacity and over 4.4 Bcf per day of peak deliverability from its storage facilities, which are located in major supply areas and near the markets it serves. NGPL owns and operates 13 underground storage reservoirs in eight field locations in four states. These storage assets complement its pipeline facilities and allow it to optimize pipeline deliveries and meet peak delivery requirements in its principal markets. NGPL provides firm and interruptible gas storage service pursuant to storage agreements and tariffs. Firm storage customers pay a monthly demand charge irrespective of actual volumes stored. Interruptible storage customers pay a monthly charge based upon actual volumes of gas stored.

Competition:  NGPL competes with other transporters of natural gas in virtually all of the markets it serves and, in particular, in the Chicago area, which is the northern terminus of NGPL’s two major pipeline segments and its largest market. These competitors include both interstate and intrastate natural gas pipelines and, historically, most of the competition has been from such pipelines with supplies originating in the United States. NGPL also faces competition from Alliance Pipeline, which began service during the 2000-2001 heating season carrying Canadian-produced natural gas into the Chicago market. However, at the same time, the Vector Pipeline was constructed for the specific purpose of transporting gas from the Chicago area to other markets, generally further north and further east. The overall impact of the increased pipeline capacity into the Chicago area, combined with additional take-away capacity and the increased demand in the area, has created a situation that remains dynamic with respect to the ultimate impact on individual transporters such as NGPL.

NGPL also faces competition with respect to the natural gas storage services it provides. NGPL has storage facilities in both market and supply areas, allowing it to offer varied storage services to customers. It faces competition from independent storage providers as well as storage services offered by other natural gas pipelines and local natural gas distribution companies.



17



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



The competition faced by NGPL with respect to its natural gas transportation and storage services is generally price-based, although there is also a significant component related to the variety, flexibility and reliability of services offered by others. NGPL’s extensive pipeline system, with access to diverse supply basins and significant storage assets in both the supply and market areas, makes it a strong competitor in many situations, but most customers still have alternative sources to meet their requirements. In addition, due to the price-based nature of much of the competition faced by NGPL, its proven track record as a low-cost provider is an important factor in its success in acquiring and retaining customers. Additional competition for storage services could result from the utilization of currently underutilized storage facilities or from conversion of existing storage facilities from one use to another. In addition, existing competitive storage facilities could, in some instances, be expanded.

Kinder Morgan Canada (Formerly Terasen Pipelines)

During 2006, Kinder Morgan Canada’s segment earnings of $119.9 million represented 8% of total segment earnings plus net pre-tax impact of Kinder Morgan Energy Partners and approximately 7% of our income from continuing operations before interest, income taxes and the impairment of goodwill on our Terasen Gas segment.

Terasen Pipelines (Trans Mountain) Inc.

Terasen Pipelines (Trans Mountain) Inc. (“Trans Mountain”) operates a common carrier pipeline system, owned by Terasen, originating at Edmonton, Alberta for the transportation of crude petroleum, refined petroleum and iso-octane to destinations in the interior and on the west coast of British Columbia. A connecting pipeline owned by a wholly owned subsidiary delivers petroleum to refineries in the State of Washington. Another wholly owned subsidiary owns and operates a six-inch diameter, 25 mile long pipeline for the transportation of jet fuel from Vancouver area refineries and marketing terminals and from Westridge Marine Terminal to Vancouver International Airport.

Trans Mountain’s pipeline is 715 miles in length and has a diameter of 24 inches for most of the line with the exception of two sections of 30-inch diameter pipeline, each having a length of approximately 51 miles. The capacity of the line out of Edmonton ranges from 225,000 bpd when heavy crude represents 20% of the total throughput to 285,000 bpd with no heavy crude. The pipeline system utilizes 11 pump stations controlled by a centralized computer system.

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 a wholly owned subsidiary. The pipeline system in Washington State has a sustainable throughput capacity of approximately 135,000 bpd 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.

The Trans Mountain pipelines are constructed on freehold lands and rights-of-way held by Trans Mountain. Crossings over or under highways, railways and bridges have been constructed pursuant to orders or permits from the appropriate authorities. Substantially all of Trans Mountain’s pipelines are constructed in rights-of-way granted by the Crown or the owners of privately-held lands, either in perpetuity for as long as they are used for a pipeline, or for fixed terms negotiated by Trans Mountain.

Under published tariffs for the Trans Mountain system, the tolls at December 31, including applicable terminalling and tankage charges, for transportation of light crude oil from Edmonton to principal delivery points are set forth below.

 

Toll Per Barrel

 

2006

 

2005

Edmonton to Burnaby

C$1.695

 

 C$1.741

Edmonton to Sumas

C$1.535

 

 C$1.560

US Mainline

US$0.30

 

US$0.30


Tolls charged to 11 shippers represented 88% of Trans Mountain’s consolidated 2006 revenues.

The petroleum transported through Trans Mountain’s pipeline system originates from fields in Alberta and British Columbia. The refined and partially refined petroleum transported to Kamloops and Vancouver originates from oil refineries located in Edmonton. Petroleum delivered through Trans Mountain’s pipeline system is used in markets in British Columbia and 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 case, the Canadian Association of Petroleum Producers (“CAPP”) has recently forecasted Western Canadian production to



18



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



increase by over 2.5 million barrels per day by 2015. This supply increase will likely result in constrained pipeline export 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 petroleum will remain strong for the foreseeable future.

In 2006, deliveries on Trans Mountain averaged 229,369 bpd. This was an increase of 4% from average 2005 deliveries of 220,886 bpd. A breakdown of total average deliveries for 2006 and 2005 is as follows:

 

(bpd)

Delivery Point:

2006

 

2005

Vancouver (crude petroleum)

46,417

 

42,482

Vancouver (refined petroleum)

49,611

 

60,634

Kamloops (refined petroleum)

15,040

 

20,366

Westridge Marine Terminal

25,206

 

22,782

Washington State refineries

93,095

 

74,622

 

229,369

 

220,886


Throughput in the U.S. pipeline system increased by 25% from 2005 levels. The year over year increase in Trans Mountain throughput reflects first quarter 2005 refinery turnarounds in Washington State and temporary production outages in the oilsands. Throughput levels in 2005 were also influenced by refined product margins on the west coast and by crude oil price differentials for Canadian crude compared against competitive offshore supply sources.

Shipments of refined petroleum represent a significant portion of Trans Mountain’s throughput. In 2006, shipments of refined petroleum and iso-octane represented 28% of throughput, as compared with 37% in 2005.

Terasen Pipelines (Corridor) Inc.

In July 1998, Trans Mountain and Terasen Inc. entered into an agreement with Shell Canada Limited (Shell) and its partners for the construction and operation of the Corridor pipeline system (Corridor Pipeline). The Corridor Pipeline is owned by our subsidiary, Terasen Pipelines (Corridor) Inc. (“Corridor”) and is operated by Kinder Morgan Canada. Revenues and commercial operation commenced in May 2003, following the successful completion of construction.

The Corridor Pipeline provides for the pipeline transportation of diluted bitumen produced at the Muskeg River Mine, located approximately 43 miles north of Fort McMurray, Alberta, to a heavy oil upgrader that Shell and its partners have built adjacent to Shell’s existing Scotford Refinery near Edmonton, Alberta, a distance of approximately 281 miles. A smaller diameter parallel pipeline transports recovered diluent from the upgrader back to the mine. Corridor also consists of two additional pipelines, each 27 miles in length, to provide pipeline transportation between the Scotford Upgrader and the existing trunk pipeline facilities of Trans Mountain and Enbridge Pipelines Inc. in the Edmonton area.

Express System

We own a one-third interest in the Express System. The Express System is a batch-mode, common-carrier, crude pipeline system comprised of the Express Pipeline and the Platte Pipeline. The Express System transports a wide variety of crude types produced in Alberta to markets in Petroleum Administration Defense District IV, comprised of the states in the Rocky Mountain area of the United States (“PADD IV”) and Petroleum Administration Defense District II, comprised of the states in the central area of the United States (“PADD II”). The Express System also transports crude oil produced in PADD IV to downstream delivery points in PADD IV and to PADD II.

The Express Pipeline is a 780 mile, 24-inch diameter pipeline that begins at the crude pipeline hub at Hardisty, Alberta and terminates at the Casper, Wyoming facilities of the Platte Pipeline, and includes related metering and storage facilities including tanks and pump stations. At Hardisty, the Express Pipeline receives crude from certain other pipeline systems and terminals, which currently provide access to approximately 1.3 million bpd of crude moving through this delivery hub. The Express Pipeline is the major pipeline transporting Alberta crude into PADD IV.

The Express Pipeline has a design capacity of 280,000 bpd, after an expansion completed in April 2005. Receipts at Hardisty averaged 226,717 bpd during the year ended December 31, 2006, compared with 212,965 bpd during the year ended December 31, 2005.

The Platte Pipeline is a 926 mile, 20-inch diameter pipeline that runs from the crude pipeline hub at Casper, Wyoming to refineries and interconnecting pipelines in the Wood River, Illinois area, and includes related pumping and storage facilities (including tanks). The Platte Pipeline transports crude shipped on the Express Pipeline, crude produced in PADD IV and crude received in PADD II, to downstream delivery points. It is currently the only major crude pipeline transporting crude oil from PADD IV to PADD II. Various receipt and delivery points along the Platte Pipeline, with interconnections to other pipelines, enable crude to be moved to various markets in PADD IV and PADD II. The Platte Pipeline has a capacity of



19



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



150,000 bpd when shipping heavy oil and averaged 151,552 bpd east of Casper during the year ended December 31, 2006, versus 137,164 bpd for the year ended December 31, 2005.

The current Express System rate structure is a combination of committed rates and uncommitted rates. The committed rates apply to those shippers who have signed long-term (10 or 15 year) contracts with the Express System to transport crude on a ship-or-pay basis. Uncommitted rates are the rates that apply to uncommitted services whereby shippers transport oil through the Express System without a long-term commitment between the shipper and the Express System.

Committed rates vary according to the destination of shipments and the length of the term of the transportation services agreement, with those shippers committing to longer-term agreements receiving lower rates.

Express Pipeline received 105,000 bpd of additional firm service commitments to the pipeline starting April 1, 2005, bringing the total firm commitment on Express to 235,000 bpd, or 84% of its total capacity. These contracts expire in 2007, 2012, 2014 and 2015 in amounts of 1%, 40%, 11% and 32% of total capacity, respectively. These contracts provide for committed tolls for transportation on the Express System, which can be increased each year by up to 2%. The remaining capacity is made available to shippers as uncommitted capacity.

Uncommitted rates were established on a cost of service basis and can be changed in accordance with applicable regulations discussed below. See “Regulation” elsewhere in this report. The table below provides a selection of tolls at December 31.

 

Toll Per Barrel (US$)

 

2006

 

2005

Hardisty, Alberta to Casper, Wyoming

$

1.612

 

$

1.552

Hardisty, Alberta to Casper, Wyoming (committed)

$

1.313

 

$

1.287

Casper, Wyoming to Wood River, Illinois

$

1.497

 

$

1.410


Competition:  Trans Mountain’s pipeline to the west coast of North America and the Express System pipeline to the U.S. Rocky Mountains and Midwest are two of several pipeline alternatives for Western Canadian petroleum production, and throughput on these pipelines may decline if overall petroleum production in Alberta declines or if tolls become uncompetitive compared to alternatives. Our oil transportation business competes against other pipeline providers who could be in a position to establish and offer lower tolls, which may provide a competitive advantage in new pipeline development. Throughput on Trans Mountain may decline in situations where west coast petroleum prices, net of transportation costs, are relatively lower than alternative prices in the U.S. Midwest. Throughput on the Express System may also decline as a result of reduced petroleum product demand in the U.S. Rocky Mountains.

Terasen Gas

On February 26, 2007, we entered into a definitive agreement to sell Terasen Inc. to Fortis Inc. (TSX: FTS), a Canada-based company with investments in regulated distribution utilities, for approximately $3.2 billion (C$3.7 billion) including cash and assumed debt. Terasen Inc.’s principal assets include Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. The transaction is subject to certain closing conditions and regulatory approvals and is expected to close in mid 2007.  This sale does not include assets of Kinder Morgan Canada.

During 2006, Terasen Gas’ segment earnings of $312.9 million represented 20% of total segment earnings plus net pre-tax impact of Kinder Morgan Energy Partners and approximately 18% of our income from continuing operations before interest, income taxes and the impairment of goodwill on our Terasen Gas segment.

Terasen Gas Inc.

Terasen Gas Inc. provides service to more than 100 communities with a service territory that has an estimated population of approximately 4.3 million. Terasen Gas Inc. is one of the largest natural gas distribution companies in Canada. As of December 31, 2006, Terasen Gas Inc. and its subsidiaries transported and distributed natural gas to 815,032 residential, commercial and industrial customers, representing approximately 87% of the natural gas users in British Columbia. Terasen Gas Inc.’s service area extends from Vancouver to the Fraser Valley and the interior of British Columbia. The transmission and distribution business is carried on under statutes and franchises or operating agreements granting the right to operate in the municipalities or areas served. Terasen Gas Inc. is regulated by the British Columbia Utilities Commission (“BCUC”).

Terasen Gas Inc. provides natural gas distribution services to residential, small commercial and industrial heating customers predominantly on a non-contractual basis, whereby the customers are charged based on general services provided. Larger commercial and industrial customers are normally provided with services on a contractual basis.

Terasen Gas Inc. has approximately 1,956 commercial and industrial customers that arrange for some or all of their own gas supply and use Terasen Gas Inc.’s transportation services for delivery. Notwithstanding shifts over time between utility



20



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



supply and direct purchases, Terasen Gas Inc.’s earnings remain unaffected since Terasen Gas Inc.’s margins remain substantially the same whether or not customers choose to buy natural gas from Terasen Gas Inc. or arrange their own supply. Customers arranging for their own supply in fact reduce the credit risk to Terasen Gas Inc.

Of Terasen Gas Inc.’s industrial customers, 143 are on interruptible service. The majority of these customers are capable of switching to alternative fuels. Forecast variances in industrial consumption can have an impact on Terasen Gas Inc.’s earnings. However, forecasts are updated annually based largely on the results of an annual survey of industrial customers.

Of the various industries that comprise Terasen Gas Inc.’s industrial market, the pulp and paper and wood products industries combined comprise approximately 47% of total consumption. All other industries individually represent less than 10% of total consumption.

In order to acquire supply resources that ensure reliable natural gas deliveries to its customers, Terasen Gas Inc. purchases supply from a select list of producers, aggregators, and marketers by adhering to strict standards of counterparty creditworthiness, and contract execution/management procedures. Terasen Gas Inc. contracts for approximately 140 PJ of baseload and seasonal supply, of which, 95 PJ is delivered off the Duke Energy Gas Transmission system, and 25 PJ is comprised of Alberta-sourced supply transported into British Columbia via TransCanada Pipelines Limited (“TransCanada”) Alberta and British Columbia systems. The remaining 20 PJ of baseload and seasonal supply is sourced at Sumas. The majority of supply contracts in the current portfolio are one year in length, with the exception of one long-term contract expiring in October 2009.

Terasen Gas Inc. serves Greater Vancouver and the Fraser Valley through a transmission and distribution system that connects to the Duke Energy Gas Transmission pipeline near Huntingdon, British Columbia. This transmission system also supplies gas to Terasen Gas (Vancouver Island) Inc. for delivery to the Sunshine Coast, Vancouver Island and to Terasen Gas (Squamish) Inc., a subsidiary of Terasen Gas Inc., for distribution in Squamish, British Columbia. In addition, Terasen Gas Inc. is connected at Huntingdon to Northwest Pipeline to facilitate gas movement both north and south. Effective January 1, 2007, Terasen Gas (Squamish) Inc. has amalgamated with Terasen Gas Inc.

In the interior of British Columbia, Terasen Gas Inc. serves municipalities with numerous connections to the Duke pipeline system. Communities in the East Kootenay region of British Columbia are served through connections with TransCanada’s British Columbia system. Terasen Gas Inc. is connected to TransCanada’s British Columbia system through Terasen Gas Inc.’s Southern Crossing Pipeline between Yahk and Oliver. Terasen Gas Inc. also operates a propane distribution system in Revelstoke, British Columbia.

The Duke and TransCanada transportation tolls are regulated by the National Energy Board (“NEB”). Terasen Gas Inc. pays both fixed and variable charges for use of the pipelines, which are recovered through rates paid by Terasen Gas Inc.’s customers.

Terasen Gas Inc. incorporates peak shaving and gas storage facilities into its portfolio to:

1.

Manage the load factor of baseload supply contracts throughout the year.

2.

Eliminate the risk of supply shortages during a peak throughput day.

3.

Reduce the cost of gas during winter months.

4.

Balance daily supply and demand on the distribution system.

5.

Supplement its baseload supply sources at times when the demand for natural gas is greatest.

Terasen Gas Inc.’s peak shaving and storage assets and contracts for 2007 include the following:

1.

Liquefied natural gas (LNG) plant: The plant is located on Tilbury Island in Delta, British Columbia, and has a capacity of approximately 660 TJ with a maximum daily deliverability rate of 165 TJ.

2.

Carbon Storage: Atco Midstream Ltd. owns and operates the Carbon storage facility in Alberta. The contract provides for 3 PJ of capacity with a maximum daily deliverability of 28 TJ.

3.

Aitken Creek Storage: Terasen Gas Inc. has storage contracts with Unocal Canada Limited which provide 20 PJ of capacity at the Aitken Creek storage facility in British Columbia, with a daily deliverability rate of 135 TJ.

4.

Jackson Prairie Storage: The Jackson Prairie storage facility is jointly owned by two U.S. Pacific Northwest gas utilities and Northwest Pipeline near Chehalis, Washington. Terasen Gas Inc. is a party to three storage lease



21



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



agreements that provide the right to approximately 3 PJ of capacity, with a maximum daily deliverability rate of about 130 TJ.

5.

Mist Storage: Terasen Gas Inc. has two contracts with Northwest Natural Gas Company for natural gas storage in Oregon. The contracts provide a total capacity of approximately 3 PJ with a maximum daily deliverability rate of 115 TJ.

Terasen Gas Inc. is eligible for incentives under the Gas Supply Mitigation Incentive Plan established with the BCUC relating to its off-system sales activities and capacity release of excess transportation and storage capacity. For the 2007 Gas Year which runs from November 2006 to October 2007, Terasen Gas Inc. has marketed approximately 27.6 PJ of surplus gas and 56.1 PJ of excess pipeline and storage capacity up to December 31, 2006, which resulted in margins eligible for incentives totaling C$39.9 million (pre-tax), of which C$1.3 million (pre-tax) accrued to Terasen Gas Inc.

As of December 31, 2006, Terasen Gas Inc. had 24,000 miles of pipelines for use in natural gas transmission and distribution. In addition to the pipelines, Terasen Gas Inc. owns properties and equipment utilized for service shops, warehouses, metering, and regulating stations, as well as its main operations center in Surrey, British Columbia.

Terasen Gas Inc.’s pipelines are constructed for the most part under highways and streets pursuant to permits or orders from the appropriate authorities, franchise or operating agreements entered into with municipalities and rights-of-way held directly or jointly with British Columbia Hydro & Power Authority (“B.C. Hydro”). Compressor stations and major regulator stations are located on freehold land, rights-of-way owned by Terasen Gas Inc. or properties shared with B.C. Hydro.

Terasen Gas Inc. currently holds operating agreements with all of the incorporated municipalities in which it distributes gas in the Greater Vancouver and Fraser Valley service areas, other than Richmond, British Columbia. The operating agreements are in force so long as the distribution lines of Terasen Gas Inc. are operative and do not contain any provision entitling the municipality to purchase the distribution system. No fees are payable by Terasen Gas Inc. under these operating agreements.

Terasen Gas Inc. currently holds franchise or operating agreements with most of the incorporated municipalities in which it distributes gas in the interior of British Columbia. Historically, approximately one-quarter of these franchise agreements contained a provision to the effect that at the end of the term the municipality could purchase the distribution system within the municipality as a going concern and at a price equal to the fair value of the business undertaking. If the municipality did not exercise the right to purchase or grant a new franchise or operating agreement, the gas utility would be required under the Utilities Commission Act to continue to provide service in the municipality unless the BCUC ordered otherwise. While such franchise agreements are in effect, the municipalities receive franchise fees of three per cent of the gross revenue from customers in the municipality. The term of the franchise agreements ranges from 10 to 21 years. Some have expired and Terasen Gas Inc. is currently negotiating renewals and extensions with the remaining municipalities, some of which have a right to purchase the distribution system within their boundaries. For those municipalities with the right to purchase those distribution systems, an arrangement has been developed to transfer the economic risks and rewards of ownership to the municipality, while allowing Terasen Gas Inc. to continue to operate within the municipality.

These arrangements have been entered into with five municipalities to date. In each of the transactions, Terasen Gas Inc. entered into an arrangement whereby the municipality leased Terasen Gas Inc.’s gas distribution assets within the municipality’s boundaries for a term of 35 years for an initial cash payment. Terasen Gas Inc. in turn entered into a 17 year operating lease with the municipality whereby Terasen Gas Inc. will operate the gas distribution assets. Terasen Gas Inc. has the option to terminate the lease of the assets to the municipality at the end of 17 years in exchange for a payment to the municipality equal to the depreciated value of the leased assets. As of December 31, 2006, Terasen Gas Inc. had entered into such arrangements involving a total value of C$153 million.

Terasen Gas (Vancouver Island) Inc.

Terasen Gas (Vancouver Island) Inc. (“TGVI”) owns and operates the natural gas transmission pipeline from the Greater Vancouver area across the Georgia Strait to Vancouver Island and the distribution system on Vancouver Island and along the Sunshine Coast of British Columbia. The combined system consists of 382 miles of natural gas transmission pipelines and 3,300 miles of distribution pipelines, some of which are under water. The combined system has a designed throughput capacity of 155 TJ per day. TGVI serves approximately 87,369 residential, commercial and industrial customers along the Sunshine Coast and in various communities on Vancouver Island including Victoria and surrounding areas, including seven pulp and paper mills on Vancouver Island and the Sunshine Coast and a natural gas-fired electricity generation facility on Vancouver Island. During 2006, TGVI delivered approximately 27.7 petajoules of gas through its system. The rate base of TGVI as of December 31, 2006 was approximately C$468.4 million.

TGVI provides gas transportation service to the seven pulp and paper mills under a long-term transportation service agreement that was amended in December 2004 to extend it beyond the original renewal period by two years to December 31, 2012. The maximum daily volume of firm transportation service under the agreement was 20 TJ per day for 2005. In



22



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



2006, the maximum daily volume changes to 12.5 TJ per day for the remainder of the renewal period. TGVI also delivers gas on both a firm (45.0 TJ per day) and interruptible basis to the gas-fired cogeneration plant at Elk Falls on Vancouver Island.

In order to acquire effective supply resources that ensure reliable natural gas deliveries to its customers, TGVI purchases supply from a select list of producers, aggregators, and marketers by adhering to strict standards of counterparty credit worthiness, and contract execution/management procedures. TGVI contracts for approximately 37.6 TJ per day of seasonal supply to meet load during the months from November 2006 to March 2007. TGVI further contracts 9.5 TJ per day of seasonal supply to meet the higher loads during the winter months from December 2006 to February 2007. 15 TJ per day of supply is contracted to meet the load requirement during summer from April 2007 to October 2007. The supply contracts in the current portfolio are for one season in length (i.e. either November to March for winter supply or April to October for summer supply).

Terasen Gas (Whistler) Inc.

Terasen Gas (Whistler) Inc. (“Whistler Gas”) distributes piped propane gas to approximately 2,370 residential and commercial customers in the Whistler area of British Columbia. Whistler Gas owns and operates two propane storage and vaporization plants and approximately 80 miles of distribution pipelines serving customers in the Whistler area. Whistler Gas is regulated by the BCUC. The rate base of Whistler Gas at December 31, 2006 was approximately C$17.0 million.

Competition:  Natural gas has maintained a competitive advantage in terms of pricing when compared with alternative sources of energy in British Columbia, despite the significant increase in natural gas commodity prices since 1999. However, because electricity prices in British Columbia continue to be set based on the historical average cost of production, rather than based on market forces, they have remained artificially low compared to market-priced electricity and, as a result, only marginally higher than comparable, market-based natural gas costs. A further sustained increase in natural gas commodity prices could cause natural gas in British Columbia to be uncompetitive with electricity, thereby decreasing the use of natural gas by customers.

Power

Power’s 2006 earnings represented approximately 1% of each of our total segment earnings plus net pre-tax impact of Kinder Morgan Energy Partners and our income from continuing operations before interest, income taxes and the impairment of goodwill on our Terasen Gas segment. We currently have ownership interests in two natural gas-fired electricity generation facilities in Colorado and one natural gas-fired electricity generation facility in Michigan. We also have a net profits interest in a third natural gas-fired electricity generation facility in Colorado. One of the Colorado facilities is operated as an independent power producer, with both a long-term power sales agreement and gas supply contract. The other Colorado facility and the Michigan facility are operated under tolling agreements. Under the tolling agreements, purchasers of the electrical output take the risks in the marketplace associated with the cost of fuel and the value of the electric power generated. Kinder Morgan Power’s customers include power marketers and utilities. During 2006, approximately 64% of Power’s operating revenues represented tolling revenues of the Michigan facility, 24% was derived from the Colorado facility operated as an independent power producer under a long-term contract with XCEL Energy’s Public Service Company of Colorado unit, and the remaining 12% were primarily for operating the Ft. Lupton, Colorado power facility and a gas-fired power facility in Snyder, Texas that began operations during the second quarter of 2005 and provides electricity to Kinder Morgan Energy Partners’ SACROC operations. In recent periods, we have recorded impairment charges associated with our power business activities; see Note 6 of the accompanying Notes to Consolidated Financial Statements.

Kinder Morgan Power previously designed, developed and constructed power projects. In 2002, following an assessment of the electric power industry’s business environment and noting a marked deterioration in the financial condition of certain power generating and marketing participants, we decided to discontinue our power development activities.

In February 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550 megawatt natural gas-fired Orion technology (discussed below) electric power plant in Jackson, Michigan. Effective July 1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC (now valued at approximately $119 million); and, (ii) Triton Power Company LLC, through its wholly owned subsidiary, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC.

In 1998, Kinder Morgan Power acquired interests in the Thermo Companies, which provided us with our first electric generation assets as well as knowledge and expertise with General Electric Company jet engines (LMs) configured in a combined cycle mode. Through the Thermo Companies, Kinder Morgan Power acquired the interests in three Colorado natural gas-fired electric generating facilities discussed above, which have a combined 380 megawatts of electric generation



23



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Business and Properties. (continued)

KMI Form 10-K



capacity. Kinder Morgan Power used the LM knowledge to develop its proprietary “Orion” technology. Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we made an additional investment in the Thermo Companies in the form of approximately 1.8 million Kinder Morgan Management shares that we owned. We delivered these shares to an entity controlled by the former Thermo owners. For further information regarding this incremental investment, see “Power” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Competition: With respect to the electric generating facilities acquired from the Thermo entities, Kinder Morgan Power does not directly face competition with respect to the sale of the power generated, as it is sold to or generated for the local electric utility under long-term contracts. With respect to Power’s investment in the Jackson, Michigan facility, the principal impact of competition is the level of dispatch of the plant and the related (but minor) effect on profitability.

Products Pipelines – KMP

The Products Pipelines – KMP segment consists of Kinder Morgan Energy Partners’ refined petroleum products and natural gas liquids pipelines and associated terminals, Southeast terminals and transmix processing facilities.

Pacific Operations

The Pacific operations include Kinder Morgan Energy Partners’ SFPP, L.P. operations, CALNEV Pipeline operations and West Coast terminals operations. The assets include interstate common carrier pipelines regulated by the FERC, intrastate pipelines in the State of California regulated by the California Public Utilities Commission, and certain non rate-regulated operations and terminal facilities.

The Pacific operations serve seven western states with approximately 3,000 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to some of the fastest growing population centers in the United States, including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor. For 2006, the three main product types transported were gasoline (61%), diesel fuel (22%) and jet fuel (17%).

The Pacific operations’ pipeline system consists of seven pipeline segments, which include the following:

·

the West Line, which consists of approximately 515 miles of primary pipeline and currently transports products for 37 shippers from six refineries and three pipeline terminals in the Los Angeles Basin to Phoenix, Arizona and various intermediate commercial and military delivery points. Products for the West Line also come through the Los Angeles and Long Beach port complexes;

·

the East Line, which is comprised of two parallel pipelines, 12-inch/16-inch diameter and 8-inch/12-inch diameter, originating in El Paso, Texas and continuing approximately 300 miles west to Kinder Morgan Energy Partners’ Tucson terminal, and one 12-inch diameter line continuing northwest approximately 130 miles from Tucson to Phoenix. Products received by the East Line at El Paso come from a refinery in El Paso and through inter-connections with non-affiliated pipelines;

·

the San Diego Line, which is a 135-mile pipeline serving major population areas in Orange County (immediately south of Los Angeles) and San Diego. The same refineries and terminals that supply the West Line also supply the San Diego Line;

·

the CALNEV Line, which consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from Kinder Morgan Energy Partners’ facilities at Colton, California to Las Vegas, Nevada, 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;

·

the North Line, which consists of approximately 864 miles of trunk pipeline in five segments that transport products from Richmond and Concord, California to Brisbane, Sacramento, Chico, Fresno, Stockton and San Jose, California, and Reno, Nevada. The products delivered through the North Line come from refineries in the San Francisco Bay Area and from various pipeline and marine terminals;

·

the Bakersfield Line, which is a 100-mile, 8-inch diameter pipeline serving Fresno, California; and

·

the Oregon Line, which is a 114-mile pipeline transporting products to Eugene, Oregon for 18 shippers from marine terminals in Portland, Oregon and from the Olympic Pipeline.

The Pacific operation’s West Coast terminals are fee-based terminals located in several strategic locations along the west coast of the United States with a combined total capacity of approximately 8.3 million barrels of storage for both petroleum



24



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Business and Properties. (continued)

KMI Form 10-K



products and chemicals. The Carson terminal and the connected Los Angeles Harbor terminal are located near the many refineries in the Los Angeles Basin. The combined Carson/LA Harbor system is connected to numerous other pipelines and facilities throughout the Los Angeles area, which gives the system significant flexibility and allows customers to quickly respond to market conditions.

The Richmond terminal is located in the San Francisco Bay Area. The facility serves as a storage and distribution center for chemicals, lubricants and paraffin waxes. It is also the principal location in northern California through which tropical oils are imported for further processing, and from which United States’ produced vegetable oils are exported to consumers in the Far East. The Pacific operations also have two petroleum product terminals located in Portland, Oregon and one in Seattle, Washington.

The Pacific operations include 15 truck-loading terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage capacity of approximately 13.5 million barrels. The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and oxygenate blending.

Markets.  Combined, the Pacific operations’ pipelines transport approximately 1.2 million barrels per day of refined petroleum products, providing pipeline service to approximately 31 customer-owned terminals, 11 commercial airports and 14 military bases. Currently, the Pacific operations’ pipelines serve approximately 93 shippers in the refined petroleum products market; the largest customers being major petroleum companies, independent refiners, and the United States military.

A substantial portion of the product volume transported is gasoline. Demand for gasoline depends on such factors as prevailing economic conditions, vehicular use patterns and demographic changes in the markets served. If current trends continue, we expect the majority of the Pacific operations’ markets to maintain growth rates that will exceed the national average for the foreseeable future. Currently, the California gasoline market is approximately one million barrels per day. The Arizona gasoline market, which is served primarily by the Pacific operations, is approximately 178,000 barrels per day. Nevada’s gasoline market is approximately 71,000 barrels per day and Oregon’s is approximately 100,000 barrels per day. The diesel and jet fuel market is approximately 545,000 barrels per day in California, 86,000 barrels per day in Arizona, 33,000 barrels per day in Nevada and 62,000 barrels per day in Oregon.

The volume of products transported is affected by various factors, principally demographic growth, economic conditions, product pricing, vehicle miles traveled, population and fleet mileage. Certain product volumes can experience seasonal variations and, consequently, overall volumes may be lower during the first and fourth quarters of each year.

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

Competition.  The most significant competitors of the Pacific operations’ pipeline system are proprietary pipelines owned and operated by major oil companies in the area where the Pacific operations’ pipeline system delivers products as well as refineries with related terminal and trucking arrangements within the Pacific operations’ 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 the Pacific operations will be built in the foreseeable future. However, the possibility of individual pipelines being constructed or expanded to serve specific markets is a continuing competitive factor.

The use of trucks for product distribution from either shipper-owned proprietary terminals or from their refining centers continues to compete for short haul movements by pipeline. We cannot predict with any certainty whether the use of short haul trucking will decrease or increase in the future.

Longhorn Partners Pipeline is a pipeline that transports refined products from refineries on the Gulf Coast to El Paso and other destinations in Texas. Increased product supply in the El Paso area has resulted in some shift of volumes transported into Arizona from the West Line to the East Line. Increased movements into the Arizona market from El Paso could displace lower tariff volumes supplied from Los Angeles on the West Line. Such shift of supply sourcing has not had, and is not expected to have, a material effect on our operating results.

The Pacific operation’s terminals compete with terminals owned by its shippers and by third party terminal operators in Sacramento, San Jose, Stockton, Colton, Orange County, Mission Valley, and San Diego, California, Phoenix and Tucson, Arizona and Las Vegas, Nevada. Short haul trucking from the refinery centers is also a competitive factor to terminals close to the refineries. Competitors of the Carson terminal in the refined products market include Shell Oil Products U.S. and BP (formerly Arco Terminal Services Company). In the crude/black oil market, competitors include Pacific Energy, Wilmington Liquid Bulk Terminals (Vopak) and BP. Competition to the Richmond terminal’s chemical business comes primarily from IMTT. Competitors to the Portland, Oregon terminals include ST Services, ChevronTexaco and Shell Oil Products U.S.



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Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Competitors to the Seattle petroleum products terminal primarily include BP and Shell Oil Products U.S.  

Plantation Pipe Line Company

Kinder Morgan Energy Partners owns approximately 51% of Plantation Pipe Line Company, a 3,100-mile refined petroleum products pipeline system serving the southeastern United States. An affiliate of ExxonMobil owns the remaining 49% ownership interest. ExxonMobil is the largest shipper on the Plantation system both in terms of volumes and revenues. Kinder Morgan Energy Partners operates the system pursuant to agreements with Plantation Services LLC and Plantation Pipe Line Company. Plantation serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area.

For the year 2006, Plantation delivered an average of 555,060 barrels per day of refined petroleum products. These delivered volumes were comprised of gasoline (67%), diesel/heating oil (20%) and jet fuel (13%). Average delivery volumes for 2006 were 6.8% lower than the 595,248 barrels per day delivered during 2005. The decrease was predominantly driven by alternative pipeline service into Southeast markets and to changes in supply patterns from Louisiana refineries related to new ultra low sulfur diesel and ethanol blended gasoline requirements.

Markets.  Plantation ships products for approximately 40 companies to terminals throughout the southeastern United States. Plantation’s principal customers are Gulf Coast refining and marketing companies, fuel wholesalers, and the United States Department of Defense. Plantation’s top five shippers represent approximately 82% of total system volumes.

The eight states in which Plantation operates represent a collective pipeline demand of approximately two million barrels per day of refined petroleum products. Plantation currently has direct access to about 1.5 million barrels per day of this overall market. The remaining 0.5 million barrels per day of demand lies in markets (e.g., Nashville, Tennessee; North Augusta, South Carolina; Bainbridge, Georgia; and Selma, North Carolina) currently served by another pipeline company. Plantation also delivers jet fuel to the Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports (Ronald Reagan National and Dulles).  Combined jet fuel shipments to these four major airports decreased 13% in 2006 compared to 2005, due primarily to a 19% decrease in shipments to Atlanta Hartsfield-Jackson International Airport and a 35% decrease in shipments to Charlotte-Douglas International airport, which was largely the result of air carriers realizing lower wholesale prices on jet fuel transported by competing pipelines.

Supply.  Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products. Plantation is directly connected to and supplied by a total of ten major refineries representing approximately 2.3 million barrels per day of refining capacity.

Competition.  Plantation competes primarily with the Colonial pipeline system, which also runs from Gulf Coast refineries throughout the southeastern United States and extends into the northeastern states.

Central Florida Pipeline

The 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 Kinder Morgan Energy Partners’ Tampa terminal, the pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Petroleum. The 10-inch diameter pipeline is connected to Kinder Morgan Energy Partners’ Taft, Florida terminal (located near Orlando) and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida. In 2006, the pipeline system transported approximately 112,000 barrels per day of refined products, with the product mix being approximately 69% gasoline, 13% diesel fuel, and 18% jet fuel.

Kinder Morgan Energy Partners also owns and operates liquids terminals in Tampa and Taft, Florida. The Tampa terminal contains approximately 1.4 million barrels of storage capacity and is connected to two ship dock facilities in the Port of Tampa. In early 2007, a new tank will go into service, increasing storage capacity to approximately 1.5 million barrels. The Tampa terminal provides storage for gasoline, diesel fuel and jet fuel for further movement into either trucks through five truck-loading racks or into the Central Florida pipeline system. The Tampa terminal also provides storage for non-fuel products, predominantly spray oil used to treat citrus crops; ethanol; and bio-diesel. These products are delivered to the terminal by vessel or railcar and loaded onto trucks through truck-loading racks. The Taft terminal contains approximately 0.7 million barrels of storage capacity, providing storage for gasoline and diesel fuel for further movement into trucks through 13 truck-loading racks.

Markets.  The estimated total refined petroleum products demand in the State of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the largest component of that demand at approximately 545,000 barrels per day. The total refined petroleum products demand for the Central Florida region of the state, which includes the Tampa and Orlando markets, is estimated to be approximately 360,000 barrels per day, or 45% of the consumption of refined products in the state. Kinder



26



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



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

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

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

With respect to the terminal operations at Tampa, the most significant competitors are proprietary terminals owned and operated by major oil companies, such as Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and the ChevronTexaco and Motiva terminals in Port Tampa. These terminals generally support the storage requirements of their parent or affiliated companies’ refining and marketing operations and provide a mechanism for an oil company to enter into exchange contracts with third parties to serve its storage needs in markets where the oil company may not have terminal assets.

Federal regulation of marine vessels, including the requirement, under the Jones Act, that United States-flagged vessels contain double-hulls, is a significant factor influencing the availability of vessels that transport refined petroleum products. Marine vessel owners are phasing in the requirement based on the age of the vessel and some older vessels are being redeployed into use in other jurisdictions rather than being retrofitted with a double-hull for use in the United States.

North System

The North System consists of an approximate 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products for approximately 50 shippers from south central Kansas to the Chicago area. Through interconnections with other major liquids pipelines, the North System’s pipeline system connects mid-continent producing areas to markets in the Midwest and eastern United States. Kinder Morgan Energy Partners also has defined sole carrier rights to use capacity on an extensive pipeline system owned by Magellan Midstream Partners, L.P. that interconnects with the North System. This capacity lease agreement, which requires Kinder Morgan Energy Partners to pay approximately $2.3 million per year, is in place until February 2013 and contains a five-year renewal option.

In addition to its capacity lease agreement with Magellan, Kinder Morgan Energy Partners also has a reversal agreement with Magellan to help provide for the transport of summer-time surplus butanes from Chicago area refineries to storage facilities at Bushton, Kansas. Kinder Morgan Energy Partners has an annual minimum joint tariff commitment of $0.6 million to Magellan for this agreement. The North System has approximately 7.7 million barrels of storage capacity, which includes caverns, steel tanks, pipeline line-fill and leased storage capacity. This storage capacity provides operating efficiencies and flexibility in meeting seasonal demands of shippers and provides propane storage for Kinder Morgan Energy Partners’ truck-loading terminals.

Kinder Morgan Energy Partners also owns a 50% ownership interest in the Heartland Pipeline Company, which owns the Heartland pipeline system, a natural gas liquids pipeline that ships liquids products in the Midwest. Kinder Morgan Energy Partners’ equity interest in Heartland is included as part of the North System operations. ConocoPhillips owns the remaining 50% interest in the Heartland Pipeline Company. The Heartland pipeline comprises one of the North System’s main line sections that originate at Bushton, Kansas and terminate at a storage and terminal area in Des Moines, Iowa. Kinder Morgan Energy Partners operates the Heartland pipeline, and ConocoPhillips operates Heartland’s Des Moines, Iowa terminal and serves as the managing partner of Heartland. Heartland leases to ConocoPhillips 100% of the Heartland terminal capacity at Des Moines for $1.0 million per year on a year-to-year basis. The Heartland pipeline lease fee, payable to Kinder Morgan Energy Partners for reserved pipeline capacity, is paid monthly, with an annual adjustment. The 2007 lease fee will be



27



Items 1. and 2.

Business and Properties. (continued)

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approximately $1.1 million.

In addition, the North System has eight propane truck-loading terminals at various points in three states along the pipeline system and one multi-product complex at Morris, Illinois, in the Chicago area. Propane, normal butane and natural gasoline can be loaded at the North System’s Morris terminal.

Markets.  The North System currently serves approximately 50 shippers in the upper Midwest market, including both users and wholesale marketers of natural gas liquids. These shippers include the three major refineries in the Chicago area. Wholesale marketers of natural gas liquids primarily make direct large volume sales to major end-users, such as propane marketers, refineries, petrochemical plants and industrial concerns. Market demand for natural gas liquids varies in respect to the different end uses to which natural gas liquids products may be applied. Demand for transportation services is influenced not only by demand for natural gas liquids but also by the available supply of natural gas liquids.

Supply.  Natural gas liquids extracted or fractionated at the Bushton gas processing plant have historically accounted for a significant portion (approximately 15%) of the natural gas liquids transported through the North System. Other sources of natural gas liquids transported in the North System include large oil companies, marketers, end-users and natural gas processors that use interconnecting pipelines to transport hydrocarbons. Refined petroleum products transported by Heartland on the North System are supplied primarily from the National Cooperative Refinery Association crude oil refinery in McPherson, Kansas and the ConocoPhillips crude oil refinery in Ponca City, Oklahoma. In an effort to obtain the greatest benefit from the North System’s line-fill on a year round basis, Kinder Morgan Energy Partners added isobutane as a component of line-fill in 2005, and increased the proportion of normal butane and reduced the proportion of propane. We believe this restructured line-fill helps mitigate any operational constraints that could result from shippers holding reduced inventory levels at any point in the year.

Competition.  The North System competes with other natural gas liquids pipelines and to a lesser extent with rail carriers. In most cases, established pipelines are the lowest cost alternative for the transportation of natural gas liquids and refined petroleum products. With respect to the Chicago market, the North System competes with other natural gas liquids pipelines that deliver into the area and with railcar deliveries primarily from Canada. Other Midwest pipelines and area refineries compete with the North System for propane terminal deliveries. The North System also competes indirectly with pipelines that deliver product to markets that the North System does not serve, such as the Gulf Coast market area. Heartland competes with other refined petroleum products carriers in the geographic market served. Heartland’s principal competitor is Magellan Midstream Partners, L.P.

Cochin Pipeline System

Kinder Morgan Energy Partners owns 49.8% of the Cochin pipeline system, a joint venture that operates an approximate 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Sarnia, Ontario, including five terminals. BP Canada Energy Company, an affiliate of BP, owns the remaining 50.2% ownership interest and is the operator of the pipeline. On January 15, 2007, Kinder Morgan Energy Partners announced that it had entered into an agreement with BP Canada Energy Company to increase its ownership interest in the Cochin pipeline system to 100%. The agreement is subject to due diligence, regulatory clearance and other standard closing conditions. The transaction is expected to close in the first quarter of 2007, and upon closing, Kinder Morgan Energy Partners will become the operator of the pipeline.

The pipeline operates on a batched basis and has an estimated system capacity of approximately 112,000 barrels per day. Its peak capacity is approximately 124,000 barrels per day. It includes 31 pump stations spaced at 60 mile intervals and five United States propane terminals. Associated underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario.

Markets.  The pipeline traverses three provinces in Canada and seven states in the United States transporting high vapor pressure ethane, propane, butane and natural gas liquids to the Midwestern United States and eastern Canadian petrochemical and fuel markets. The system operates as a National Energy Board (Canada) and FERC (United States) regulated common carrier, shipping products on behalf of its owners as well as other third parties. The system is connected to the Enterprise pipeline system in Minnesota and in Iowa, and connects with the North System at Clinton, Iowa. The Cochin pipeline system has the ability to access the Canadian Eastern Delivery System via the Windsor Storage Facility Joint Venture at Windsor, Ontario.

Supply. Injection into the system can occur from BP, EnerPro or Dow fractionation facilities at Fort Saskatchewan, Alberta; from Provident Energy storage at five points within the provinces of Canada; or from the Enterprise West Junction, in Minnesota.

Competition.  The pipeline competes with railcars and Enbridge Energy Partners for natural gas liquids long-haul business from Fort Saskatchewan, Alberta and Windsor, Ontario. The pipeline’s primary competition in the Chicago natural gas



28



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



liquids market comes from the combination of the Alliance pipeline system, which brings unprocessed gas into the United States from Canada, and from Aux Sable, which processes and markets the natural gas liquids in the Chicago market.

Cypress Pipeline

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

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

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

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

Southeast Terminals

Kinder Morgan Energy Partners’ Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this report as KMST, was formed in 2003 for the purpose of acquiring and operating high-quality liquid petroleum products terminals located primarily along the Plantation/Colonial pipeline corridor in the Southeastern United States.

Since its formation, KMST has acquired 24 petroleum products terminals with a total storage capacity of approximately 7.8 million barrels. These terminals transferred approximately 347,000 barrels of refined products per day during 2006.

The 24 terminals consist of the following:

·

seven petroleum products terminals acquired from ConocoPhillips and Phillips Pipe Line Company in December 2003. The terminals are located in the following markets: Selma, North Carolina; Charlotte, North Carolina; Spartanburg, South Carolina; North Augusta, South Carolina; Doraville, Georgia; Albany, Georgia; and Birmingham, Alabama. The terminals contain approximately 1.2 million barrels of storage capacity. ConocoPhillips has entered into a long-term contract with Kinder Morgan Energy Partners to use the terminals. All seven terminals are served by the Colonial Pipeline and three are also connected to the Plantation Pipeline;

·

seven petroleum products terminals acquired from Exxon Mobil Corporation in March 2004. The terminals are located at the following locations: Newington, Virginia; Richmond, Virginia; Roanoke, Virginia; Greensboro, North Carolina; Charlotte, North Carolina; Knoxville, Tennessee; and Collins, Mississippi. The terminals have a combined storage capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel fuel. ExxonMobil has entered into a long-term contract to use the terminals. All seven of these terminals are connected to products pipelines owned by either Plantation Pipe Line Company or Colonial Pipeline Company;

·

nine petroleum products terminals acquired from Charter Terminal Company and Charter-Triad Terminals in November 2004. Three terminals are located in Selma, North Carolina, and the remaining facilities are located in Greensboro and Charlotte, North Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta, South Carolina. The terminals have a combined storage capacity of approximately 3.2 million barrels for gasoline, jet fuel and diesel fuel. Kinder Morgan Energy Partners fully owns seven of the terminals and jointly owns the remaining two. All nine terminals are connected to Plantation or Colonial pipelines; and

·

one petroleum products terminal acquired from Motiva Enterprises, LLC in December 2006. The terminal, located in Roanoke, Virginia, has storage capacity of approximately 180,000 barrels per day for refined petroleum products and is served exclusively by the Plantation Pipeline. Motiva Enterprises, LLC has entered into a long-term contract to use the terminal.

Markets.  KMST’s acquisition and marketing activities are focused on the Southeastern United States from Mississippi through Virginia, including Tennessee. The primary function involves the receipt of petroleum products from common



29



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KMI Form 10-K



carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks. Longer term storage is also available at many of the terminals. KMST has a physical presence in markets representing almost 80% of the pipeline-supplied demand in the Southeast and offers a competitive alternative to marketers seeking a relationship with a truly independent truck terminal service provider.

Supply.  Product supply is predominately from Plantation and/or Colonial pipelines. To the maximum extent practicable, we endeavor to connect KMST terminals to both Plantation and Colonial.

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

Transmix Operations

Kinder Morgan Energy Partners’ Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process. During transportation, different products are transported through the pipelines abutting each other, and the volume of different mixed products is called transmix. At transmix processing facilities, pipeline transmix is processed and separated into pipeline-quality gasoline and light distillate products. Kinder Morgan Energy Partners processes transmix at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina.

At the Dorsey Junction, Maryland facility, transmix processing is performed for Colonial Pipeline Company on a “for fee” basis pursuant to a long-term contract that expires in 2012. Transmix is processed on a “for fee” basis for Shell Trading (U.S.) Company, referred to as Shell, according to the provisions of a long-term contract that expires in 2011 at Kinder Morgan Energy Partners’ transmix facilities located in Richmond, Virginia; Indianola, Pennsylvania; and Wood River, Illinois. At these locations, Shell procures transmix supply from pipelines and other parties, pays a processing fee to Kinder Morgan Energy Partners, and then sells the processed gasoline and fuel oil through their marketing and distribution networks. The arrangement includes a minimum annual processing volume and a per barrel fee to Kinder Morgan Energy Partners, as well as an opportunity to extend the processing agreement beyond 2011.

The Colton processing facility is located adjacent to the products terminal in Colton, California, and it produces refined petroleum products that are delivered into the Pacific operations’ pipelines for shipment to markets in Southern California and Arizona. The facility can process over 5,000 barrels of transmix per day. In June 2006, Duke Energy Merchants exercised an early termination provision contained in Kinder Morgan Energy Partners’ long term processing contract due to expire in 2010. Following Duke’s exercise, Kinder Morgan Energy Partners transitioned to processing transmix at Colton for various pipeline shippers directly on a “for fee” basis arrangement.

The Richmond, Virginia processing facility is supplied by the Colonial and Plantation pipelines as well as deep-water barges (25 feet draft), transport truck and rail.  The facility can process approximately 7,500 barrels per day. The Dorsey Junction processing facility is located within Colonial’s Dorsey Junction terminal facility, near Baltimore, Maryland. The facility can process approximately 5,000 barrels per day. The Indianola processing facility is located near Pittsburgh, Pennsylvania and is accessible by truck, barge and pipeline. It primarily processes transmix from the Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process 12,000 barrels of transmix per day. The Wood River processing facility is constructed on property owned by ConocoPhillips and is accessible by truck, barge and pipeline. It primarily processes transmix from both the Explorer and ConocoPhillips pipelines. It has capacity to process 5,000 barrels of transmix per day.

In the second quarter of 2006, Kinder Morgan Energy Partners completed construction and placed into service its approximately $11 million Greensboro, North Carolina transmix facility, which is located along KMST’s refined products tank farm. The facility includes an atmospheric distillation column with a direct fired natural gas heater to process up to 6,000 barrels of transmix per day for Plantation and other interested parties. In addition to providing additional processing business, the facility also gives Plantation a lower cost alternative that recovers ultra low sulfur diesel, and more fully utilizes current KMST tankage at the Greensboro, North Carolina tank farm.

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



30



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



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

Competition.  Placid Refining is Kinder Morgan Energy Partners’ 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 Kinder Morgan Energy Partners’ transmix facilities. A new transmix facility located near Linden, New Jersey and owned by Motiva Enterprises LLC is the principal competition for New York Harbor transmix supply and for the Indianola facility. A number of smaller organizations operate transmix processing facilities in the West and Southwest. These operations compete for supply that we envision as the basis for growth in the West and Southwest. The Colton processing facility also competes with major oil company refineries in California.

Natural Gas Pipelines – KMP

The Natural Gas Pipelines – KMP segment, which contains both interstate and intrastate pipelines, consists of natural gas sales, transportation, storage, gathering, processing and treating. Within this segment, Kinder Morgan Energy Partners owns approximately 14,000 miles of natural gas pipelines and associated storage and supply lines that are strategically located at the center of the North American pipeline grid. The transportation network provides access to the major gas supply areas in the western United States, Texas and the Midwest, as well as major consumer markets.

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:

·

Kinder Morgan Texas Pipeline;

·

Kinder Morgan Tejas Pipeline;

·

Mier-Monterrey Mexico Pipeline; and

·

Kinder Morgan North Texas Pipeline.

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

Collectively, the system primarily serves the Texas Gulf Coast, transporting, processing and treating gas from multiple onshore and offshore supply sources to serve the Houston/Beaumont/Port Arthur, Texas industrial markets, as well as local gas distribution utilities, electric utilities and merchant power generation markets. It serves as a buyer and seller of natural gas, as well as a transporter of natural gas. The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of its system. The difference between the purchase and sale prices is the rough equivalent of a transportation fee and fuel costs.

Included in the operations of the Kinder Morgan Tejas system is the Kinder Morgan Border Pipeline system. Kinder Morgan Border owns and operates an approximately 97-mile, 24-inch diameter pipeline that extends from a point of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica 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.

The 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. Kinder Morgan Energy Partners has entered into a long-term contract (expiring in 2018) with Pemex, which has subscribed for all of the pipeline’s capacity.



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The North Texas Pipeline consists of an 86-mile, 30-inch diameter pipeline that transports natural gas from an interconnect with 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 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.

Kinder Morgan Energy Partners also owns and operates various gathering systems in South and East Texas. These systems aggregate natural gas supplies into Kinder Morgan Energy Partners’ main transmission pipelines, and in certain cases, aggregate natural gas that must be processed or treated at its own or third-party facilities. Kinder Morgan Energy Partners owns two processing plants: the Texas City Plant in Galveston County, Texas and the Galveston Bay Plant in Chambers County, Texas, which is currently idle. Combined, these plants can process 115 million cubic feet per day of natural gas for liquids extraction. In addition, Kinder Morgan Energy Partners has contractual rights to process approximately 800 million cubic feet per day of natural gas at various third-party owned facilities. Kinder Morgan Energy Partners also owns and operates three natural gas treating plants that offer carbon dioxide and/or hydrogen sulfide removal. Kinder Morgan Energy Partners can treat up to 155 million cubic feet per day of natural gas for carbon dioxide removal at the Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at the Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic feet per day of natural gas at the Thompsonville Facility located in Jim Hogg County, Texas.  

The North Dayton natural gas storage facility, located in Liberty County, Texas, has two existing storage caverns providing approximately 6.3 billion cubic feet of total capacity, consisting of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of pad gas. Kinder Morgan Energy Partners entered into a long-term storage capacity and transportation agreement with Texas Genco covering two billion cubic feet of natural gas working capacity that expires in March 2017.

In June 2006, Kinder Morgan Energy Partners announced an expansion project that will significantly increase natural gas storage capacity at the North Dayton facility. The project is expected to cost between $76 million and $82 million and involves the development of a new underground storage cavern that will add an estimated 5.5 billion cubic feet of incremental working natural gas storage capacity. The additional capacity is expected to be available in mid-2009.

Kinder Morgan Energy Partners also owns the West Clear Lake natural gas storage facility located in Harris County, Texas. Under a long term contract, Coral Energy Resources, L.P. operates the facility and controls the 96 billion cubic feet of natural gas working capacity, and Kinder Morgan Energy Partners provides transportation service into and out of the facility.

Additionally, Kinder Morgan Energy Partners leases a salt dome storage facility located near Markham, Texas, according to the provisions of an operating lease that expires in March 2013. Kinder Morgan Energy Partners can, at its sole option, extend the term of this lease for two additional ten-year periods. The facility currently consists of three salt dome caverns with approximately 10.0 billion cubic feet of working natural gas capacity and up to 750 million cubic feet per day of peak deliverability. A fourth cavern, with an additional 7.0 billion cubic feet of working natural gas capacity, is expected to be in service the second quarter of 2007. Kinder Morgan Energy Partners also leases two salt dome caverns, known as the Stratton Ridge Facilities, from BP America Production Company in Brazoria County, Texas. The Stratton Ridge Facilities have a combined working natural gas capacity of 1.4 billion cubic feet and a peak day deliverability of 100 million cubic feet per day. A lease with Dow Hydrocarbon & Resources, Inc. for a salt dome cavern containing approximately 5.0 billion cubic feet of working capacity expires during the third quarter of 2007, and we do not expect to extend the lease.

Markets. Texas is one of the largest natural gas consuming states in the country. The natural gas demand profile in Kinder Morgan Energy Partners’ Texas intrastate pipeline group’s market area is primarily composed of industrial (including on-site cogeneration facilities), merchant and utility power and to a lesser extent local natural gas distribution consumption. The industrial demand is primarily year-round load. Merchant and utility power demand peaks in the summer months and is complemented by local natural gas distribution demand that peaks in the winter months. As new merchant gas fired generation has come online and displaced traditional utility generation, Kinder Morgan Energy Partners has successfully attached many of these new generation facilities to its pipeline systems in order to maintain and grow its share of natural gas supply for power generation. Additionally, in 2007, Kinder Morgan Energy Partners has increased its capability and commitment to serve the growing local natural gas distribution market in the greater Houston metropolitan area.

Kinder Morgan Energy Partners serves the Mexico market through interconnection with the facilities of Pemex at the United States-Mexico border near Arguellas, Mexico and Monterrey, Mexico. In 2006, deliveries through the existing interconnection near Arguellas fluctuated from zero to approximately 218 million cubic feet per day of natural gas, and there were several days of exports to the United States which ranged up to 202 million cubic feet per day. Deliveries to Monterrey also ranged from zero to 322 million cubic feet per day. Kinder Morgan Energy Partners primarily provides transport service to these markets on a fee for service basis, including a significant demand component, which is paid regardless of actual throughput. Revenues earned from Kinder Morgan Energy Partners’ activities in Mexico are paid in U.S. dollar equivalent.

Supply.  Kinder Morgan Energy Partners purchases its natural gas directly from producers attached to its system in South Texas, East Texas and along the Texas Gulf Coast. Kinder Morgan Energy Partners also purchases gas at interconnects with



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third-party interstate and intrastate pipelines. While the intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area. The intrastate system has access to both onshore and offshore sources of supply, and 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. Kinder Morgan Energy Partners competes with interstate and intrastate pipelines, and their shippers, for attachments to new markets and supplies and for transportation, processing and treating services.

Kinder Morgan Interstate Gas Transmission LLC

Kinder Morgan Interstate Gas Transmission LLC, referred to in this report as KMIGT, along with Trailblazer Pipeline Company, TransColorado Gas Transmission Company, and a current 51% ownership interest in the Rockies Express Pipeline (all discussed following) comprise Kinder Morgan Energy Partners’ four Rocky Mountain interstate natural gas pipeline systems.

KMIGT owns approximately 5,100 miles of transmission lines in Wyoming, Colorado, Kansas, Missouri and Nebraska. The pipeline system is powered by 28 transmission and storage compressor stations with approximately 160,000 horsepower. KMIGT also owns the Huntsman natural gas storage facility, located in Cheyenne County, Nebraska, which has approximately 10 billion cubic feet of firm capacity commitments and provides for withdrawal of up to 169 million cubic feet of natural gas per day.

Under transportation agreements and FERC tariff provisions, KMIGT offers its customers firm and interruptible transportation and storage services, including no-notice park and loan services. For these services, KMIGT charges rates that include the retention of fuel and gas lost and unaccounted for in-kind. Under KMIGT’s tariffs, firm transportation and storage customers pay reservation fees each month plus a commodity charge based on the actual transported or stored volumes. In contrast, interruptible transportation and storage customers pay a commodity charge based upon actual transported and/or stored volumes. Under the no-notice service, customers pay a fee for the right to use a combination of firm storage and firm transportation to effect deliveries of natural gas up to a specified volume without making specific nominations. KMIGT also has the authority to make gas purchases and sales, as needed for system operations, pursuant to its currently effective FERC gas tariff.

KMIGT also offers its Cheyenne Market Center service, which provides nominated storage and transportation service between its Huntsman storage field and multiple interconnecting pipelines at the Cheyenne Hub, located in Weld County, Colorado. This service is fully subscribed through May 2014.

Markets. Markets served by KMIGT provide a stable customer base with expansion opportunities due to the system’s access to growing Rocky Mountain supply sources. Markets served by KMIGT are comprised mainly of local natural gas distribution companies and interconnecting interstate pipelines in the mid-continent area. End-users of the local natural gas distribution companies typically include residential, commercial, industrial and agricultural customers. The pipelines interconnecting with KMIGT in turn deliver gas into multiple markets including some of the largest population centers in the Midwest. Natural gas demand to power pumps for crop irrigation during the summer from time-to-time exceeds heating season demand and provides KMIGT relatively consistent volumes throughout the year. In addition, KMIGT has seen a significant increase in demand from ethanol producers, and is actively seeking ways to meet the demands from the ethanol producing community.

Supply.  Approximately 5%, by volume, of KMIGT’s firm contracts expire within one year and 61% expire within one to five years. Over 99% of the system’s total firm transport capacity is currently subscribed, and affiliates are responsible for approximately 30% of the total contracted firm transportation and storage capacity on KMIGT’s system. The majority of this affiliated business is dedicated to our U.S. retail natural gas distribution operations, and in August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations. Pending regulatory approvals, we expect this transaction to close by the end of the first quarter of 2007.

Competition.  KMIGT competes with other interstate and intrastate gas pipelines transporting gas from the supply sources in the Rocky Mountain and Hugoton Basins to mid-continent pipelines and market centers.

Trailblazer Pipeline Company

The Trailblazer Pipeline Company owns a 436-mile natural gas pipeline system that originates at an interconnection with Wyoming Interstate Company Ltd.’s pipeline system near Rockport, Colorado and runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it interconnects with NGPL’s and Northern Natural Gas Company’s pipeline systems. NGPL manages, maintains and operates Trailblazer, for which it is reimbursed at cost.



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Trailblazer’s pipeline is the fourth and last segment of a 791-mile pipeline system known as the Trailblazer Pipeline System, which originates in Uinta County, Wyoming with Canyon Creek Compression Company, a 22,000 horsepower compressor station located at the tailgate of BP’s processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek’s facilities are the first segment). Canyon Creek receives gas from the BP processing plant and provides transportation and compression of gas for delivery to Overthrust Pipeline Company’s 88-mile, 36-inch diameter pipeline system at an interconnection in Uinta County, Wyoming (Overthrust’s system is the second segment). Overthrust delivers gas to Wyoming Interstate’s 269-mile, 36-inch diameter pipeline system at an inter-connection (Kanda) in Sweetwater County, Wyoming (Wyoming Interstate’s system is the third segment). Wyoming Interstate’s pipeline delivers gas to Trailblazer’s pipeline at an interconnection near Rockport in Weld County, Colorado.

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

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

Supply.  As of December 31, 2006, approximately 16% of Trailblazer’s firm contracts, by volume, expire before one year and 19%, by volume, expire within one to five years. Affiliated entities hold less than 1% of the total firm transportation capacity. All of the system’s firm transport capacity is currently subscribed.

Competition.  The main competition that Trailblazer currently faces is that the gas supply in the Rocky Mountain area either stays in the area or is moved west and therefore is not transported on Trailblazer’s pipeline. In addition, El Paso’s Cheyenne Plains Pipeline can transport approximately 730 million cubic feet per day of natural gas from Weld County, Colorado to Greensburg, Kansas and competes with Trailblazer for natural gas pipeline transportation demand from the Rocky Mountain area. Additional competition could come from proposed pipeline projects such as the Rockies Express Pipeline. No assurance can be given that additional competing pipelines will not be developed in the future.

TransColorado Gas Transmission Company

The TransColorado Gas Transmission Company owns a 300-mile interstate natural gas pipeline that extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield, New Mexico. It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies. The pipeline system is powered by six compressor stations having an aggregate of approximately 30,000 horsepower. Kinder Morgan, Inc. manages, maintains and operates TransColorado, for which it is reimbursed at cost.

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

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

On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado filed an application for authorization to construct and operate certain facilities comprising its Blanco-Meeker Expansion Project. Upon approval, this project will facilitate additional market access to Rocky Mountain gas production by transporting up to 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing facilities for deliveries to the Rockies Express Pipeline at an existing point of interconnection located at the Meeker Hub in Rio Blanco County, Colorado.  A prearranged shipper has executed a binding precedent agreement for all capacity on the project. The total expansion project is expected to cost approximately $58 million.



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Markets.  TransColorado acts principally as a feeder pipeline system from the developing natural gas supply basins on the Western Slope of Colorado into the interstate natural gas pipelines that lead away from the Blanco Hub area of New Mexico and the interstate natural gas pipelines that lead away eastward from northwestern Colorado and southwestern Wyoming. TransColorado is the largest transporter of natural gas from the Western Slope supply basins of Colorado and provides a competitively attractive outlet for that developing natural gas resource. In 2006, TransColorado transported an average of approximately 869 million cubic feet per day of natural gas from these supply basins, an increase of 30% over the previous year. The increase in transportation deliveries was partially due to the completion of TransColorado’s north system expansion project, which was placed in-service on January 1, 2006. The expansion provided for up to 300 million cubic feet per day of additional northbound transportation capacity, and was supported by a long-term contract with Williams Companies, Inc. that runs through 2015, with an option for a five-year extension.

Supply.  During 2006, 83% of TransColorado’s transport business was with producers or their own marketing affiliates and 15% was with gathering companies, and the remaining 2% was with various gas marketers. Approximately 70% of TransColorado’s transport business in 2006 was conducted with its two largest customers. All of TransColorado’s southbound pipeline capacity is committed under firm transportation contracts that extend at least through year-end 2007. TransColorado’s pipeline capacity is 93% subscribed during 2007 through 2011 and TransColorado is actively pursuing contract extensions and or replacement contracts to increase firm subscription levels beyond 2007.

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

Historically, the competition faced by TransColorado with respect to its natural gas transportation services has generally been based upon the price differential between the San Juan and Rocky Mountain basins. Competing pipelines servicing these producing basins have had the effect of reducing that price differential; however, given the increased number of direct connections to production facilities in the Piceance and Paradox basins and the gas supply development in each of those basins, we believe that TransColorado’s transport business will be less susceptible to changes in the price differential in the future.

Rockies Express Pipeline

Kinder Morgan Energy Partners operates and currently owns 51% of the 1,662-mile Rockies Express Pipeline system, which when fully completed, will be one of the largest natural gas pipelines ever constructed in North America. The approximately $4.4 billion project will have the capability to transport 1.8 billion cubic feet per day of natural gas, and binding firm commitments have been secured for virtually all of the pipeline capacity. The pipeline is owned by Rockies Express Pipeline LLC, a wholly-owned subsidiary of West2East Pipeline LLC, and as of December 31, 2006, Kinder Morgan Energy Partners owned 51%, Sempra Energy held a 25% ownership interest and ConocoPhillips owned the remaining 24% ownership interest. When construction of the entire project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50% and the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economics in the project. We do not anticipate any additional changes in the ownership structure of the project.

The first part of the Rockies Express Pipeline is referred to in this report as Rockies Express-Entrega, and consists of a 327-mile section that runs from the Meeker Hub in northwest Colorado, across southern Wyoming to the Cheyenne Hub in Weld County, Colorado. The first 136-miles of 36-inch diameter pipeline from the Meeker Hub to the Wamsutter Hub in Sweetwater County, Wyoming, provided interim service in 2006 during the construction and completion of the second pipeline segment, a 191-mile, 42-inch diameter line extending from the Wamsutter Hub to the Cheyenne Hub. The completed construction of the second segment from the Wamsutter Hub to the Cheyenne Hub on February 14, 2007, signified the completion of phase one of the total Rockies Express – Entrega project.

On May 31, 2006, Rockies Express Pipeline LLC filed an application with the FERC for authorization to construct and operate certain facilities comprising its proposed Rockies Express-West project. This project is the first planned segment extension of Rockies Express-Entrega, described above. The Rockies Express-West project will be comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment extension proposes to transport approximately 1.5 billion cubic feet per day of natural gas across the following five states: Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub. On September 21, 2006, the FERC made a preliminary determination that the issuance of a



35



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certificate to Rockies Express under the provisions of the Natural Gas Act to construct and operate the Rockies Express-West Project, and enter into a lease with Questar Overthrust Pipeline Company, would on the basis of all non-environmental issues be required by the public convenience and necessity. On December 27, 2006, Rockies Express and TransColorado filed their joint responses to the FERC’s Draft Environmental Impact Statement. Rockies Express expects to receive final FERC approval in March 2007, and plans to begin construction in May 2007, with a targeted in-service date of January 1, 2008.

The final segment of the Rockies Express Pipeline, referred to as Rockies Express-East, consists of an approximate 635-mile pipeline segment that will extend from eastern Missouri to the Clarington Hub in eastern Ohio. Rockies Express will file a separate application in the future for this proposed Rockies Express-East project. In June 2006, Kinder Morgan Energy Partners made the National Environmental Policy Act pre-filing for Rockies Express-East with the FERC. From September 11-15, 2006, the FERC hosted nine scoping meetings for the preparation of an Environmental Impact Statement along the proposed route. Rockies Express-East is expected to begin interim service as early as December 31, 2008, and to be fully completed by June 2009.

Kinder Morgan Louisiana Pipeline  

In September 2006, Kinder Morgan Energy Partners filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline. The natural gas pipeline project is expected to cost approximately $500 million and will provide approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron Parish, Louisiana. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total, and in exchange for shipper commitments to the project, Kinder Morgan Energy Partners has granted options to acquire equity in the project, which, if fully exercised, could result in Kinder Morgan Energy Partners owning a minimum interest of 80% after the project is completed.

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 in the second quarter of 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.

Kinder Morgan Energy Partners has designed and will construct the Kinder Morgan Louisiana Pipeline in a manner that will minimize environmental impacts, and where possible, existing pipeline corridors will be used to minimize impacts to communities and to the environment. As of December 31, 2006, there were no major pipeline re-routes as a result of any landowner requests. Kinder Morgan Energy Partners is currently finalizing pipeline interconnect agreements, preparing detailed designs of the facilities, attending FERC inter-agency meetings and acquiring pipeline right-of-way.

Casper and Douglas Natural Gas Gathering and Processing Systems

Kinder Morgan Energy Partners owns and operates the Casper, Wyoming natural gas processing plant, which is a lean oil absorption facility with full fractionation and has capacity to process up to 70 million cubic feet per day of natural gas depending on raw gas quality. The inlet composition of gas entering the Casper plant averages approximately 1.5 gallons per thousand cubic feet of propane and heavier natural gas liquids, reflecting the relatively lean gas gathered and delivered to the Casper plant.

Kinder Morgan Energy Partners also owns and operates the Douglas natural gas processing facility, located in Douglas, Wyoming. The Douglas plant is capable of processing approximately 115 million cubic feet of natural gas per day. The plant is a cryogenic facility which recovers the full range of natural gas liquids from ethane through natural gasoline. The plant also has a stabilizer capable of capturing heavy end natural gas liquids for sale into local markets at a premium price. Residue gas is delivered from the plant into KMIGT and recovered liquids are injected in ConocoPhillips Petroleum’s natural gas liquids pipeline for transport to Borger, Texas.

Effective April 1, 2006, Kinder Morgan Energy Partners sold its Wyoming natural gas gathering system and its Painter Unit fractionation facility to a third party for approximately $42.5 million in cash. For more information on this sale, see Note 5 to our consolidated financial statements included elsewhere in this report.



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

Competition. Other regional facilities in the Greater Powder River Basin include the Hilight plant (80 million cubic feet per day) owned and operated by Anadarko, the Sage Creek plant (50 million cubic feet per day) owned and operated by Merit Energy, and the Rawlins plant (50 million cubic feet per day) owned and operated by El Paso. Casper and Douglas, however, are the only plants which provide straddle processing of natural gas flowing into KMIGT.

Red Cedar Gathering Company

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

Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as Coyote Gulch. Previously, Kinder Morgan Energy Partners owned a 50% equity interest in Coyote Gulch and Enterprise Field Services LLC owned the remaining 50%. Effective March 1, 2006, the Southern Ute Indian Tribe acquired Enterprise’s 50% interest in Coyote Gulch. Kinder Morgan Energy Partners and the Tribe agreed to a resolution that would transfer all of the members’ equity in Coyote Gulch to the members’ equity of Red Cedar, and effective September 1, 2006, Coyote Gulch was a wholly owned subsidiary of Red Cedar.

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

Red Cedar’s gas gathering system currently consists of over 1,100 miles of gathering pipeline connecting more than 920 producing wells, 85,000 horsepower of compression at 24 field compressor stations and two carbon dioxide treating plants. A majority of the natural gas on the system moves through 8-inch to 16-inch diameter pipe. The capacity and throughput of the Red Cedar system as currently configured is approximately 750 million cubic feet per day of natural gas.

Thunder Creek Gas Services, LLC

Kinder Morgan Energy Partners owns a 25% equity interest in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek. Devon Energy owns the remaining 75%. Thunder Creek provides gathering, compression and treating services to a number of coal seam gas producers in the Powder River Basin of Wyoming. Throughput volumes include both coal seam and conventional plant residue gas. Thunder Creek is independently operated from offices located in Denver, Colorado with field offices in Glenrock and Gillette, Wyoming.

Thunder Creek’s operations are a combination of mainline and low pressure gathering assets. The mainline assets include 125 miles of 24-inch diameter mainline pipeline, 230 miles of 4-inch to 12-inch diameter high and low pressure laterals, 24,265 horsepower of mainline compression and carbon dioxide removal facilities consisting of a 240 million cubic feet per day carbon dioxide treating plant complete with dehydration. The mainline assets receive gas from 52 receipt points and can deliver treated gas to seven delivery points including Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power plants. The low pressure gathering assets include five systems consisting of 194 miles of 4-inch to 14-inch diameter gathering pipeline and 35,400 horsepower of field compression. Gas is gathered from 101 receipt points and delivered to the mainline at seven primary locations.

CO2 – KMP

The CO2 – KMP segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates, referred to in this report as KMCO2. Carbon dioxide is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. KMCO2’s carbon dioxide pipelines and related assets allow Kinder Morgan Energy Partners to market a complete package of carbon dioxide supply, transportation and technical expertise to the customer. Together, the CO2 – KMP business segment produces, transports and markets carbon dioxide for use in enhanced oil recovery operations. Kinder



37



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Morgan Energy Partners also holds ownership interests in several oil-producing fields and owns a 450-mile crude oil pipeline, all located in the Permian Basin region of West Texas.

Carbon Dioxide Reserves

Kinder Morgan Energy Partners owns approximately 45% of, and operates, the McElmo Dome unit, which contains more than nine trillion cubic feet of recoverable carbon dioxide. Deliverability and compression capacity exceeds one billion cubic feet per day. The McElmo Dome unit is located in Montezuma County, Colorado and produces from the Leadville formation at approximately 8,000 feet with 54 wells that combined, produced an average of 973 million cubic feet per day in 2006. Kinder Morgan Energy Partners also owns approximately 11% of the Bravo Dome unit, which contains reserves of approximately two trillion cubic feet of recoverable carbon dioxide. Located in the northeast quadrant of New Mexico, the Bravo Dome unit produces approximately 290 million cubic feet per day, with production coming from more than 350 wells in the Tubb Sandstone at 2,300 feet.

Kinder Morgan Energy Partners also owns approximately 88% of the Doe Canyon Deep unit, which contains more than 1.5 trillion cubic feet of carbon dioxide. Kinder Morgan Energy Partners is currently installing facilities and six wells to produce an average of 100 million cubic feet per day of carbon dioxide beginning in January 2008. The Doe Canyon Deep unit is located in Delores County, Colorado, and it will produce from the Leadville formation at approximately 8,800 feet.

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

Competition.  Kinder Morgan Energy Partners’ primary competitors for the sale of carbon dioxide include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves, and 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 Kinder Morgan Energy Partners or that new methodologies for enhanced oil recovery will not replace carbon dioxide flooding.

Carbon Dioxide Pipelines

As a result of its 50% ownership interest in Cortez Pipeline Company, Kinder Morgan Energy Partners owns a 50% equity interest in and operates the approximate 500-mile, 30-inch diameter Cortez pipeline. The pipeline carries carbon dioxide from the McElmo Dome source reservoir in Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently transports nearly one billion cubic feet of carbon dioxide per day, including approximately 99% of the carbon dioxide transported downstream on the Central Basin pipeline and the Centerline pipeline, both described following.

Kinder Morgan Energy Partners’ Central Basin pipeline consists of approximately 143 miles of 16-inch to 26-inch diameter pipe and 177 miles of 4-inch to 12-inch diameter 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, the Central Basin pipeline interconnects with all three major carbon dioxide supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines (operated by Occidental and Trinity CO2, respectively). Central Basin’s mainline terminates near McCamey where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the Central Basin pipeline are not regulated.

Kinder Morgan Energy Partners’ Centerline pipeline consists of approximately 113 miles of 16-inch diameter pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas. The pipeline has a capacity of 300 million cubic feet per day. The tariffs charged by the Centerline pipeline are not regulated.

Kinder Morgan Energy Partners owns a 13% undivided interest in the 218-mile, 20-inch diameter Bravo pipeline, which delivers to the Denver City hub and has a capacity of more than 350 million cubic feet per day. Major delivery points along the line include the Slaughter field in Cochran and Hockley Counties, Texas, and the Wasson field in Yoakum County, Texas. Tariffs on the Cortez and Bravo pipelines are not regulated.

In addition, Kinder Morgan Energy Partners owns approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a 16-inch diameter, a capacity of approximately 290 million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The Pecos pipeline is a 25-mile, 8-inch diameter pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 million cubic feet per day of carbon dioxide and makes deliveries to the Yates unit. The tariffs charged on the Canyon Reef Carriers and Pecos pipelines are not regulated.



38



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Markets.  The principal market for transportation on KMCO2’s carbon dioxide pipelines is to customers, including Kinder Morgan Energy Partners, using carbon dioxide for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to grow modestly for the next several years.

Competition.  Kinder Morgan Energy Partners’ ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other carbon dioxide pipelines. Kinder Morgan Energy Partners also competes with other interest owners in McElmo Dome and Bravo Dome for transportation of carbon dioxide to the Denver City, Texas market area.

Oil Reserves

KMCO2 also holds ownership interests in oil-producing fields, including an approximate 97% working interest in the SACROC unit, an approximate 50% working interest in the Yates unit, a 21% net profits interest in the H.T. Boyd unit, an approximate 65% working interest in the Claytonville unit, an approximate 95% working interest in the Katz CB Long unit, an approximate 64% working interest in the Katz SW River unit, a 100% working interest in the Katz East River unit, and lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit, all of which are located in the Permian Basin of West Texas.

The SACROC unit is one of the largest and oldest oil fields in the United States using carbon dioxide flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.29 billion barrels of oil since inception. It is estimated that SACROC originally held approximately 2.7 billion barrels of oil. We have expanded the development of the carbon dioxide project initiated by the previous owners and increased production over the last several years. The Yates unit is also one of the largest oil fields ever discovered in the United States. It is estimated that it originally held more than five billion barrels of oil, of which about 28% has been produced. The field, discovered in 1926, is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.

As of December 2006, the SACROC unit had 355 producing wells, and the purchased carbon dioxide injection rate was 247 million cubic feet per day, down from an average of 258 million cubic feet per day as of December 2005. The average oil production rate for 2006 was approximately 30,800 barrels of oil per day, down from an average of approximately 32,400 barrels of oil per day during 2005. The average natural gas liquids production rate (net of the processing plant share) for 2006 was approximately 5,700 barrels per day, down from an average of approximately 6,000 barrels per day during 2005.

Kinder Morgan Energy Partners’ plan has been to increase the production rate and ultimate oil recovery from Yates by combining horizontal drilling with carbon dioxide injection to ensure a relatively steady production profile over the next several years. Kinder Morgan Energy Partners is implementing its plan and as of December 2006, the Yates unit was producing about 27,000 barrels of oil per day. As of December 2005, the Yates unit was producing approximately 24,000 barrels of oil per day. Unlike operations at SACROC, where carbon dioxide and water is used to drive oil to the producing wells, Kinder Morgan Energy Partners is using carbon dioxide injection to replace nitrogen injection at Yates in order to enhance the gravity drainage process, as well as to maintain reservoir pressure. The differences in geology and reservoir mechanics between the two fields mean that substantially less capital will be needed to develop the reserves at Yates than is required at SACROC.

Kinder Morgan Energy Partners also operates and owns an approximate 64.5% gross working interest in the Claytonville oil field unit located in Fisher County, Texas. The Claytonville unit is located nearly 30 miles east of the SACROC unit in the Permian Basin of West Texas and is currently producing approximately 200 barrels of oil per day. Kinder Morgan Energy Partners is presently evaluating operating and subsurface technical data from the Claytonville unit to further assess redevelopment opportunities including carbon dioxide flood operations.

On April 5, 2006, Kinder Morgan Energy Partners purchased various oil and gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an aggregate consideration of approximately $63.9 million, consisting of $60.3 million in cash and $3.6 million in assumed liabilities. The acquisition was effective March 1, 2006. However, since the acquisition, Kinder Morgan Energy Partners divested certain acquired properties that were not considered candidates for carbon dioxide enhanced oil recovery, and received proceeds of approximately $27.1 million from the sale of these properties. The retained properties, referred to in this report as the Katz field, are the Katz CB Long unit, the Katz Southwest River unit and Katz East River unit. The Katz field is primarily located in the Permian Basin area of West Texas and New Mexico and, as of December 2006, was producing approximately 430 barrels of oil equivalent per day. Kinder Morgan Energy Partners is presently evaluating operating and subsurface technical data to further assess redevelopment opportunities for the Katz field including the potential for carbon dioxide flood operations.

Oil Acreage and Wells

The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which Kinder Morgan Energy Partners owns interests as of December 31, 2006. When used with respect to acres or wells, gross refers to



39



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



the total acres or wells in which Kinder Morgan Energy Partners has a working interest; net refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by Kinder Morgan Energy Partners:

 

Productive Wellsa

 

Service Wellsb

 

Drilling Wells c

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Crude Oil

2,604

 

1,590

 

1,078

 

766

 

2

 

2

Natural Gas

8

 

4

 

28

 

14

 

 

  Total Wells

2,612

 

1,594

 

1,106

 

780

 

2

 

2

__________


a

Includes active wells and wells temporarily shut-in. As of December 31, 2006, Kinder Morgan Energy Partners did not operate any gross wells with multiple completions.

b

Consists of injection, water supply, disposal wells and service wells temporarily shut-in. A disposal well is used for disposal of saltwater into an underground formation; a service well is a well drilled in a known oil field in order to inject liquids that enhance recovery or dispose of salt water.

c

Consists of development wells in the process of being drilled as of December 31, 2006. A development well is a well drilled in an already discovered oil field.

The oil and gas producing fields in which Kinder Morgan Energy Partners owns interests are located in the Permian Basin area of West Texas and New Mexico. The following table reflects Kinder Morgan Energy Partners’ net productive and dry wells that were completed in each of the three years ended December 31, 2006, 2005 and 2004:

 

2006

 

2005

 

2004

Productive

 

 

 

 

 

Development

37

 

42

 

31

Exploratory

-

 

-

 

-

Dry

 

 

 

 

 

Development

-

 

-

 

-

Exploratory

-

 

-

 

-

Total Wells

37

 

42

 

31

__________


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 Kinder Morgan Energy Partners held as of December 31, 2006:

 

Gross

 

Net

Developed Acres

72,435

 

67,709

Undeveloped Acres

 8,788

 

 8,131

Total

81,223

 

75,840




40



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Operating Statistics

Operating statistics from Kinder Morgan Energy Partners’ oil and gas producing activities for each of the years 2006, 2005 and 2004 are shown in the following table:

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

 

Year Ended December 31,

 

2006

 

2005

 

2004

Consolidated Companiesa

 

 

 

 

 

 

 

 

Production Costs per Barrel of Oil Equivalentb, c, d

$

13.30

 

$

10.00

 

$

9.71

Crude Oil Production (MBbl/d)

 

37.8

 

 

37.9

 

 

32.5

Natural Gas Liquids Production (MBbl/d)d

 

5.0

 

 

5.3

 

 

3.7

Natural Gas liquids Production from Gas Plants(MBbl/d)e

 

3.9

 

 

4.1

 

 

4.0

Total Natural Gas Liquids Production(MBbl/d)

 

8.9

 

 

9.4

 

 

7.7

Natural Gas Production (MMcf/d)d, f

 

1.3

 

 

3.7

 

 

4.4

Natural Gas Production from Gas Plants(MMcf/d)e, f

 

0.3

 

 

3.1

 

 

3.9

Total Natural Gas Production(MMcf/d)f

 

1.6

 

 

6.8

 

 

8.3

Average Sales Prices Including Hedge Gains/Losses:

 

 

 

 

 

 

 

 

Crude Oil Price per Bblg

$

31.42

 

$

27.36

 

$

25.72

Natural Gas Liquids Price per Bblg

$

43.52

 

$

38.79

 

$

31.37

Natural Gas Price per Mcfh

$

6.36

 

$

5.84

 

$

5.27

Total Natural Gas Liquids Price per Bble

$

43.90

 

$

38.98

 

$

31.33

Total Natural Gas Price per Mcfe

$

7.02

 

$

5.80

 

$

5.24

Average Sales Prices Excluding Hedge Gains/Losses:

 

 

 

 

 

 

 

 

Crude Oil Price per Bblg

$

63.27

 

$

54.45

 

$

40.91

Natural Gas Liquids Price per Bblg

$

43.52

 

$

38.79

 

$

31.68

Natural Gas Price per Mcfh

$

6.36

 

$

5.84

 

$

5.27

__________


a

Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated subsidaries.

b

Computed using production costs, excluding transportation costs, as defined by the Securities and Exchange Commisson. Natural gas volumes were converted to barrels of oil equivalent (BOE) using a conversion factor of six mcf of natural gas to one barrel of oil.

c

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

d

Includes only production attributable to leasehold ownership.

e

Includes production attributable to Kinder Morgan Energy Partners’ 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.

Gas Plant Interests

Kinder Morgan Energy Partners operates and owns an approximate 22% working interest plus an additional 26% net profits interest in the Snyder gasoline plant. Kinder Morgan Energy Partners also operates and owns a 51% ownership interest in the Diamond M gas plant and a 100% ownership interest in the North Snyder plant, all of which are located in the Permian Basin of West Texas.  The Snyder gasoline plant processes gas produced from the SACROC unit and neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas. The Diamond M and the North Snyder plants contract with the Snyder plant to process gas. Production of natural gas liquids at the Snyder gasoline plant as of December 2006 was approximately 15,000 barrels per day, the same rate of production as of December 2005.



41



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Crude Oil Pipeline

Kinder Morgan Energy Partners owns the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck off-loading stations. The entire system is all located within the State of Texas, and the 20-inch diameter segment that runs from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per day (with the use of a drag reducing agent). The pipeline allows Kinder Morgan Energy Partners to better manage crude oil deliveries from its oil field interests in West Texas, and Kinder Morgan Energy Partners has entered into a long-term throughput agreement with Western Refining Company, L.P. to transport crude oil into Western’s 120,000 barrel per day refinery in El Paso. The 20-inch pipeline segment transported approximately 113,000 barrels of oil per day in 2006. The Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad Commission.

Terminals – KMP

The Terminals – KMP segment includes the operations of Kinder Morgan Energy Partners’ petroleum, chemical and other liquids terminal facilities (other than those included in the Products Pipelines – KMP segment) as well as all of Kinder Morgan Energy Partners’ coal, petroleum coke, steel and dry-bulk material services, including all transload, engineering, conveying and other in-plant services. Combined, the segment is composed of approximately 94 owned or operated liquids and bulk terminal facilities, and more than 60 rail transloading and materials handling facilities located throughout the United States. In 2006, the number of customers from whom the Terminals – KMP segment received more than $0.1 million of revenue was approximately 550.

Liquids Terminals

The liquids terminal operations primarily store refined petroleum products, petrochemicals, industrial chemicals and vegetable oil products in aboveground storage tanks and transfer products to and from pipelines, tank trucks, tank barges, and tank railcars. Combined, the liquids terminal facilities possess liquids storage capacity of approximately 43.5 million barrels, and in 2006, these terminals handled approximately 555.2 million barrels of petroleum, petrochemical and vegetable oil products. Major liquids terminal assets of this segment are described below.

The Houston, Texas terminal complex is located in Pasadena and Galena Park, Texas, along the Houston Ship Channel. Recognized as a distribution hub for Houston’s refineries situated on or near the Houston Ship Channel, the Pasadena and Galena Park terminals are the western Gulf Coast refining community’s central interchange point. The complex has approximately 19.6 million barrels of capacity and is connected via pipeline to 14 refineries, four petrochemical plants and ten major outbound pipelines. In addition, the facilities have four ship docks and seven barge docks for inbound and outbound movement of products. The terminals are served by the Union Pacific railroad.

In September 2006, Kinder Morgan Energy Partners announced major expansions at its 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 the Pasadena and Galena Park terminals; (ii) an additional cross-channel pipeline to increase the connectivity between the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional loading bay at the fully automated truck loading rack located at the 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.

Kinder Morgan Energy Partners owns three liquids facilities in the New York Harbor area: one in Carteret, New Jersey, one in Perth Amboy, New Jersey, and one on Staten Island, New York. The Carteret facility is located along the Arthur Kill River just south of New York City and has a capacity of approximately 7.5 million barrels of petroleum and petrochemical products. The Carteret facility has two ship docks and four barge docks. It is connected to the Colonial, Buckeye, Sun and Harbor pipeline systems, and the CSX and Norfolk Southern railroads service the facility. The Perth Amboy facility is also located along the Arthur Kill River and has a capacity of approximately 2.3 million barrels of petroleum and petrochemical products. Tank sizes range from 2,000 barrels to 300,000 barrels. The Perth Amboy terminal provides chemical and petroleum storage and handling, as well as dry-bulk handling of salt and aggregates. In addition to providing product movement via vessel, truck and rail, Perth Amboy has direct access to the Buckeye and Colonial pipelines. The facility has one ship dock and one barge dock, and is connected to the CSX and Norfolk Southern railroads.

In January 2006, Kinder Morgan Energy Partners announced the investment of approximately $45 million for the construction of new liquids storage tanks at Perth Amboy. The Perth Amboy expansion will involve the construction of nine new storage tanks with a capacity of 1.4 million barrels for gasoline, diesel and jet fuel service. The expansion was driven by continued strong demand for refined products in the Northeast, much of which is being met by imported fuel arriving via the New York Harbor. Due to inconsistencies in the soils underneath these tanks, we now estimate that the tank foundations will cost significantly more than our original budget, bringing the total investment to approximately $56 million and delaying the in-service date to the third quarter of 2007.



42



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



The two New Jersey facilities offer a viable alternative for moving petroleum products between the refineries and terminals throughout the New York Harbor and both are New York Mercantile Exchange delivery points for gasoline and heating oil. Both facilities are connected to the Intra Harbor Transfer Service, an operation that offers direct outbound pipeline connections that allow product to be moved from over 20 Harbor delivery points to destinations north and west of New York City.

Kinder Morgan Energy Partners also owns the Kinder Morgan Staten Island terminal on Staten Island, New York. The facility is bounded to the north and west by the Arthur Kill River and covers approximately 200 acres, of which 120 acres are used for site operations. The terminal has a storage capacity of approximately 3.0 million barrels for gasoline, diesel fuel and fuel oil. The facility also maintains and operates an above ground piping network to transfer petroleum products throughout the operating portion of the site, and Kinder Morgan Energy Partners is currently rebuilding ship and barge berths at the facility that will accommodate tanker vessels.

Kinder Morgan Energy Partners owns two liquids terminal facilities in the Chicago area: one facility is located in Argo, Illinois, approximately 14 miles southwest of downtown Chicago, and the other is located in the Port of Chicago along the Calumet River. The Argo facility is a large petroleum product and ethanol blending facility and a major break bulk facility for large chemical manufacturers and distributors. It has approximately 2.5 million barrels of capacity in tankage ranging from 50,000 gallons to 80,000 barrels. The Argo terminal is situated along the Chicago sanitary and ship channel, and has three barge docks. The facility is connected to TEPPCO and Westshore pipelines, and has a direct connection to Midway Airport. The Canadian National railroad services this facility. The Port of Chicago facility handles a wide variety of liquid chemicals with a working capacity of approximately 795,000 barrels in tanks ranging from 12,000 gallons to 55,000 barrels. The facility provides access to a full slate of transportation options, including a deep water barge/ship berth on Lake Calumet, and offers services including truck loading and off-loading, iso-container handling and drumming. There are two ship docks and four barge docks, and the facility is served by the Norfolk Southern railroad.

Two of Kinder Morgan Energy Partners’ other largest liquids facilities are located in South Louisiana: the Port of New Orleans facility located in Harvey, Louisiana, and the St. Gabriel terminal, located near a major petrochemical complex in Geismar, Louisiana. The New Orleans facility handles a variety of liquids products such as chemicals, vegetable oils, animal fats, alcohols and oil field products. It has approximately 3.0 million barrels of tankage ranging in sizes from 17,000 gallons to 200,000 barrels. There are three ship docks and one barge dock, and the Union Pacific railroad provides rail service. The terminal can be accessed by vessel, barge, tank truck, or rail, and also provides ancillary services including drumming, packaging, warehousing, and cold storage services.

The St. Gabriel facility is located approximately 75 miles north of the New Orleans facility on the bank of the Mississippi River near the town of St. Gabriel, Louisiana. The facility has approximately 340,000 barrels of tank capacity and the tanks vary in sizes ranging from 63,000 gallons to 80,000 barrels. There are three local pipeline connections at the facility, which enable the movement of products from the facility to the petrochemical plants in Geismar, Louisiana.

In June 2006, Kinder Morgan Energy Partners announced the construction of a new $115 million crude oil tank farm located in Edmonton, Alberta, Canada, and long-term contracts with customers for all of the available capacity at the facility. Situated on approximately 24 acres, the new storage facility will have nine tanks with a combined storage capacity of approximately 2.2 million barrels for crude oil. Service is expected to begin in the fourth quarter of 2007, and when completed, the tank farm will serve as a premier blending and storage hub for Canadian crude oil. The tank farm will have access to more than 20 incoming pipelines and several major outbound systems, including a connection with our 710-mile Trans Mountain Pipeline system, which currently transports up to 225,000 barrels per day of heavy crude oil and refined products from Edmonton to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state.

Competition.  Kinder Morgan Energy Partners is one of the largest independent operators of liquids terminals in North America. Its primary competitors are IMTT, Magellan, Morgan Stanley, Oil Tanking, Teppco, Valero and Vopak.

Bulk Terminals

Kinder Morgan Energy Partners’ bulk terminal operations primarily involve dry-bulk material handling services; however, Kinder Morgan Energy Partners also provides terminal engineering and design services and in-plant services covering material handling, conveying, maintenance and repair, railcar switching and miscellaneous marine services. Combined, Kinder Morgan Energy Partners’ dry-bulk and material transloading facilities handled approximately 89.5 million tons of coal, petroleum coke, steel and other dry-bulk materials in 2006. Kinder Morgan Energy Partners owns or operates approximately 28 petroleum coke or coal terminals in the United States. Major bulk terminal assets of this segment are described below.

In 2006, Kinder Morgan Energy Partners handled approximately 16.6 million tons of petroleum coke, as compared to approximately 12.3 million tons in 2005. Petroleum coke is a by-product of the crude oil refining process and has



43



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



characteristics similar to coal. It is used in domestic utility and industrial steam generation facilities. It is also used by the steel industry in the manufacture of ferro alloys, and for the manufacture of carbon and graphite products. Petroleum coke supply in the United States has increased in the last several years due to an increasingly heavy crude oil supply and also to the increased use of coking units by domestic refineries. A portion of the petroleum coke we handle is imported from or exported to foreign markets. Most of Kinder Morgan Energy Partners’ customers are large integrated oil companies that choose to outsource the storage and loading of petroleum coke for a fee.

The overall increase in petroleum coke volumes in 2006 versus 2005 was largely driven by incremental volumes attributable to Kinder Morgan Energy Partners’ purchase of certain petroleum coke terminal operations from Trans-Global Solutions, Inc. in April 2005. Kinder Morgan Energy Partners paid an aggregate consideration of approximately $247.2 million for these operations, and the acquisition made Kinder Morgan Energy Partners the largest independent handler of petroleum coke in the United States, in terms of volume. All of the acquired assets are located in the State of Texas, and include facilities at the Port of Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship Channel. The facilities also provide handling and storage services for a variety of other bulk materials.

In 2006, Kinder Morgan Energy Partners also handled approximately 30.8 million tons of coal. Coal continues to be the fuel of choice for electric generation plants, accounting for more than 50% of United States electric generation feedstock. Forecasts of overall coal usage and power plant usage for the next 20 years show an increase of about 1.5% per year. Current domestic supplies are predicted to last for several hundred years. Most coal transloaded through Kinder Morgan Energy Partners’ coal terminals is destined for use in coal-fired electric generation facilities.

The Cora terminal is a high-speed, rail-to-barge coal transfer and storage facility. The terminal is located on approximately 480 acres of land along the upper Mississippi River near Chester, Illinois, about 80 miles south of St. Louis, Missouri. It currently has a throughput capacity of about 10 million tons per year and is currently equipped to store up to one million tons of coal. This storage capacity provides customers the flexibility to coordinate their supplies of coal with the demand at power plants. The Cora terminal sits on the mainline of the Union Pacific Railroad and is strategically positioned to receive coal shipments from the western United States.

The Grand Rivers, Kentucky terminal is a coal transloading and storage facility located along the Tennessee River just above the Kentucky Dam. The terminal is operated on land under easements with an initial expiration of July 2014 and has current annual throughput capacity of approximately 12 million tons with a storage capacity of approximately one million tons. The Grand Rivers terminal provides easy access to the Ohio-Mississippi River network and the Tennessee-Tombigbee River system. The Paducah & Louisville Railroad, a short line railroad, serves Grand Rivers with connections to seven Class I rail lines including the Union Pacific, CSX, Illinois Central and Burlington Northern Santa Fe.

The Cora and Grand Rivers terminals handle low sulfur coal originating in Wyoming, Colorado, and Utah, as well as coal that originates in the mines of southern Illinois and western Kentucky. However, since many shippers, particularly in the East, are using western coal or a mixture of western coal and other coals as a means of meeting environmental restrictions, we anticipate that growth in volume through the two terminals will be primarily due to increased use of western low sulfur coal originating in Wyoming, Colorado and Utah.

The Pier IX terminal is located in Newport News, Virginia. The terminal has the capacity to transload approximately 12 million tons of coal annually. It can store 1.4 million tons of coal on its 30-acre storage site. For coal, the terminal offers blending services and rail to storage or direct transfer to ship; for other dry bulk products, the terminal offers ship to storage to rail or truck. The Pier IX terminal exports coal to foreign markets, serves power plants on the eastern seaboard of the United States, and imports cement pursuant to a long-term contract. The terminal operates a cement facility which has the capacity to transload over 400,000 tons of cement annually. Pier IX also operates two synfuel plants on site, which together produced 3.3 million tons of synfuel in 2006. The Pier IX terminal is served by the CSX Railroad, which transports coal from central Appalachian and other eastern coal basins. Cement imported to the Pier IX terminal primarily originates in Europe.

In March 2006, Kinder Morgan Energy Partners announced that it entered into a long-term agreement with Drummond Coal Sales, Inc. that will support a $70 million expansion of the Pier IX terminal. The project includes the construction of a new ship dock and the installation of additional equipment, and it is expected to increase throughput at the terminal by approximately 30% and to allow the terminal to begin receiving shipments of imported coal. The expansion project is expected to be completed in the first quarter of 2008. Upon completion, the terminal will have an import capacity of up to 9 million tons annually.

The Shipyard River terminal is located in Charleston, South Carolina, on 208 acres, and is both a bulk and liquids terminal. The Shipyard facility is able to unload, store and reload coal, petroleum coke, cement and other bulk products imported from or exported to various foreign countries. The imported coal is often a cleaner-burning, low-sulfur coal and it is used by local utilities to comply with the U.S. Clean Air Act. The Shipyard River terminal has the capacity to handle approximately 2.5 million tons of coal and petroleum coke per year and offers approximately 300,000 tons of total storage, of which 50,000 tons are under roof. The facility is serviced by the Norfolk Southern and CSX railroads. Kinder Morgan Energy Partners is



44



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



currently expanding the Shipyard River terminal in order to increase the terminal’s throughput and to allow for the handling of increasing supplies of imported coal. In addition, the terminal has over 1.0 million barrels of liquid storage capacity in 18 tanks.

The Kinder Morgan Tampaplex terminal, a marine terminal located in Tampa, Florida, sits on a 114-acre site and serves as a storage and receipt point for imported fertilizer, aggregates and ammonia, as well as an export location for dry bulk products, including fertilizer and animal feed. The terminal also includes an inland bulk storage warehouse facility used for overflow cargoes from Kinder Morgan Energy Partners’ Port Sutton import terminal, which is also located in Tampa. The Port Sutton terminal sits on 16 acres of land and offers 200,000 tons of covered storage. Primary products handled in 2006 included fertilizers, salt, ores, and liquid chemicals. Also in the Tampa Bay area are Kinder Morgan Energy Partners’ Port Manatee and Hartford Street terminals. Port Manatee has four warehouses which can store 130,000 tons of bulk products. Products handled at Port Manatee include fertilizers, ores and other general cargo. At the Hartford Street terminal, anhydrous ammonia and fertilizers are handled and stored in two warehouses with an aggregate capacity of 23,000 net tons.

The Kinder Morgan Fairless Hills terminal consists of substantially all of the assets used to operate the major port distribution facility located at the Fairless Industrial Park in Bucks County, Pennsylvania. Located on the bend of the Delaware River below Trenton, New Jersey, the terminal is the largest port on the East Coast for the handling of semi-finished steel slabs. The facility also handles other types of specialized cargo that caters to the construction industry and service centers that use steel sheet and plate. The port has four ship berths with a total length of 2,200 feet and a maximum draft of 38.5 feet. It contains two mobile harbor cranes and is served by connections to two Class I rail lines: CSX and Norfolk Southern.

The Pinney Dock terminal is located in Ashtabula, Ohio along Lake Erie. It handles iron ore, titanium ore, magnetite and other aggregates. Pinney Dock has six docks with 15,000 feet of vessel berthing space, 200 acres of outside storage space, 400,000 feet of warehouse space and two 45-ton gantry cranes.

The Chesapeake Bay bulk terminal facility is located at Sparrows Point, Maryland. It offers stevedoring services, storage, and rail, ground, or water transportation for products such as coal, petroleum coke, iron and steel slag, and other mineral products. It offers both warehouse and approximately 100 acres of open storage.

The Milwaukee and Dakota dry-bulk commodity facilities are located in Milwaukee, Wisconsin and St. Paul, Minnesota, respectively. The Milwaukee terminal is located on 34 acres of property leased from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt. The Dakota terminal is on 55 acres in St. Paul and primarily handles salt, grain products and cement. The Dakota terminal has a cement loading facility for unloading cement from barges and railcars, conveying and storing product, and loading and weighing trucks and railcars. It covers nearly nine acres and can handle approximately 400,000 tons of cement each year.

Competition. Kinder Morgan Energy Partners’ petroleum coke and other bulk terminals compete with numerous independent terminal operators, other terminals owned by oil companies, stevedoring companies and other industrials opting not to outsource terminal services. Many of Kinder Morgan Energy Partners’ other bulk terminals were constructed pursuant to long-term contracts for specific customers. As a result, we believe other terminal operators would face a significant disadvantage in competing for this business. The Cora and Grand Rivers coal terminals compete with two third-party coal terminals that also serve the Midwest United States. While the Cora and Grand Rivers terminals are modern high capacity coal terminals, some volume is diverted to these third-party terminals by the Tennessee Valley Authority in order to promote increased competition. The Pier IX terminal competes primarily with two modern coal terminals located in the same Virginian port complex as the Pier IX terminal.

Materials Services (rail transloading)

Kinder Morgan Energy Partners’ materials services operations include the rail or truck transloading operations owned by Kinder Morgan Materials Services LLC, Lomita Rail Terminal LLC, Kinder Morgan Texas Terminals, L.P., Transload Services, LLC and other stevedoring and in-plant operations. In 2006, Kinder Morgan Energy Partners acquired all of the membership interests of Lomita Rail Terminal LLC and Transload Services, LLC, and the terminal assets and operations of A&L Trucking, L.P. For more information on these acquisitions, see Note 4 to our consolidated financial statements included elsewhere in this report.

The materials services operations consist of approximately 61 rail transloading facilities, of which 56 are located east of the Mississippi River. The CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail service for these terminal facilities. Approximately 50% of the products handled are liquids, including an entire spectrum of liquid chemicals, and 50% are dry bulk products. Many of the facilities are equipped for bi-modal operation (rail-to-truck, and truck-to-rail). Kinder Morgan Energy Partners also designs and builds transloading facilities, performs inventory management services, and provides value-added services such as blending, heating and sparging. In 2006, the materials services operations handled approximately 72,000 railcars.



45



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Regulation

Interstate Common Carrier Pipeline Rate Regulation – U.S. Operations

Our petroleum products pipelines are interstate common carrier pipelines, subject to regulation by the Federal Energy Regulatory Commission under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC, which tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

On October 24, 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA. The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates we charge for transportation service on our North System and Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-day period established by the Energy Policy Act. For this reason, we believe these rates should be grandfathered under the Energy Policy Act. Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act. Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, subject to complaints with the FERC, as is more fully described in Note 19 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.

During the first quarter of 2003, the FERC made a significant positive adjustment to the index which petroleum products pipelines use to adjust their regulated tariffs for inflation. The former index used percent growth in the producer price index for finished goods, and then subtracted one percent. The index adjustment in 2003 eliminated the one percent reduction. Pursuant to a subsequent review of the index by the FERC in 2005, the index is now measured by the producer price index for finished goods plus 1.3% and it applies for years 2006 through 2010. As a result, we filed for indexed rate adjustments on a number of our petroleum products pipelines and realized benefits from the new index.

Interstate Natural Gas Pipeline Regulation – U.S. Operations

Under the Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas Policy Act of 1978, the FERC regulates both the performance of interstate transportation and storage services by interstate natural gas pipeline companies, and the rates charged for such services. The rates, terms and conditions of such services are subject to tariffs approved by the FERC. Rates are designed to recover an interstate pipeline’s costs of providing service, including financing costs, and to provide an opportunity to earn a reasonable and fair return on common equity. The rates that are set do not guaranty that a fair and reasonable return will be earned, and actual returns may vary from year to year according to various factors, including the total amount of services under contract, new investment, and increases in the cost of providing service.

In establishing the rates that an interstate pipeline may charge its customers, the FERC will generally consider an interstate pipeline’s rate base investment, costs, and revenues for a given test period, with adjustments for known and measurable changes. It will also look at the interstate pipeline’s capital structure and the cost of capital to determine whether existing rates need to be adjusted to establish new rates which are just and reasonable and sufficient to provide an opportunity to earn a fair and reasonable return on rate base. Rate base is generally the net depreciated cost of property, plant and equipment that is used or useful in providing service. A fair and reasonable return is established by determining the cost of individual components of the capital structure, including debt costs and a return on common equity, and weighting such costs to determine an aggregate return on rate base. The FERC also regulates the construction of pipelines and facilities used to transport or store natural gas in interstate commerce. Those wishing to build facilities or operate pipelines first must obtain a Certificate of Public Convenience and Necessity from the FERC.



46



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Beginning in the mid-1980’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

·

Order No. 436 (1985) 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:

·

requiring the unbundling of sales services from other services;

·

permitting holders of firm capacity on interstate natural gas pipelines to release all or a part of their capacity for resale by the pipeline; and

·

the issuance of blanket sales certificates to interstate pipelines for unbundled services.

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. The effective date of Order No. 2004 was September 22, 2004. Our interstate natural gas pipelines have implemented compliance with these Standards of Conduct.

On November 17, 2006, the D.C. Circuit vacated Order No. 2004, as applied to natural gas pipelines, and remanded the Order back to the FERC. On January 9, 2007, the FERC issued an interim rule regarding standards of conduct in Order No. 690 to be effective immediately. The interim rule repromulgated the standards of conduct that were not challenged before the court. On January 18, 2007, the FERC issued a notice of proposed rulemaking soliciting comments on whether or not the interim rule should be made permanent for natural gas transmission providers. Please refer to Note 18 to our consolidated financial statements included elsewhere in this report for additional information regarding FERC Order No. 2004 and other Standards of Conduct rulemaking.

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

California Public Utilities Commission Rate Regulation

The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the California Public Utilities Commission under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates could also arise with respect to our intrastate rates. Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 19 to our consolidated financial statements.



47



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Regulation of Canada-based Assets

Terasen Gas

Terasen Gas Inc.

Gas utilities in British Columbia are subject to the regulatory jurisdiction of the BCUC which derives its powers from the Utilities Commission Act (British Columbia). In addition to approving the rate base and new financings of Terasen Gas Inc., the BCUC also approves the rates charged to customers. These rates are designed to recover the utility’s costs of providing service and allow the opportunity to meet financial commitments and earn a reasonable and fair return on common equity. The BCUC has jurisdiction to regulate and approve the terms and conditions under which gas utilities provide service.

As part of the establishment of the rates that a gas utility charges its customers, the BCUC establishes a rate base, approves a capital structure with which to finance such rate base, and is responsible for setting a reasonable and fair return on the debt and equity in the approved capital structure. Rate base is the aggregate of the depreciated cost of property, plant and equipment that are used or useful in serving the public, certain deferral accounts and a reasonable allowance for working capital. The fair return is established by determining the cost of individual components of the capital structure, including return on common equity, and weighting such costs to determine an aggregate return on rate base. The rates that are established and the terms and conditions of service are contained in a schedule of published and public tariffs. Before any tariff can be put into effect, it must be filed with and approved by the BCUC. The BCUC has jurisdiction to approve or refuse any tariff amendment submitted for filing and to determine the rates which should be charged by a utility for its services. The BCUC is required to have due regard, among other things, to fixing rates that are not unjust or unreasonable. In fixing rates the BCUC must determine that such rates reflect a fair and reasonable charge for service of the nature and quality furnished by Terasen Gas Inc. to its customers and that such rates are sufficient to yield Terasen Gas Inc. a fair and reasonable compensation for its services and a fair and reasonable return on its rate base.

The BCUC uses a future test year in the establishment of rates for a utility. Pursuant to this method, the BCUC approves Terasen Gas Inc.’s forecast volume of gas that will be sold and transported, together with all of the costs (including the rate of return) that Terasen Gas Inc. will incur in the test year. Rates are fixed to permit Terasen Gas Inc. to collect all of its costs (including the rate of return) if the forecast sales and transportation volumes are achieved. The forecast sales volumes assume normal weather. Certain costs are fixed and will be incurred regardless of the actual volume of gas sold. Accordingly, if the actual volumes of gas sales are less than those forecast in the test year, Terasen Gas Inc. might not recover all of the fixed costs. Interest expense, taxes other than income taxes, depreciation and amortization, certain operations and maintenance costs, the portion of the cost of gas that is fixed such as demand charges or reservation fees, and the fixed portion of transportation costs have the effect of being virtually fixed costs.

Two mechanisms to ameliorate unanticipated changes in sales volumes, such as changes caused by weather, have been implemented specifically for Terasen Gas Inc. The first relates to the recovery of all gas costs through deferral accounts which capture all variances (overages and shortfalls) from forecasts. Balances are either refunded to or recovered from customers via an application with the BCUC. The deferral accounts are called the Commodity Cost Reconciliation Account and the Midstream Cost Reconciliation Account. The second mechanism seeks to stabilize delivery revenues from residential and commercial customers through a deferral account that captures variances in the forecast versus actual customer use throughout the year. This mechanism is called the Revenue Stabilization Adjustment Mechanism. In February 2001, the BCUC issued guidelines for quarterly calculations to be prepared to determine whether customer rate adjustments are needed to reflect prevailing market prices for natural gas and to ensure that rate stabilization account balances are recovered on a timely basis.

Terasen Gas Inc. also has in place short-term and long-term interest rate deferral accounts to absorb interest rate fluctuations. The interest rate deferral accounts that were in place during 2006 effectively fixed the interest expense on short-term funds attributable to Terasen Gas Inc.’s regulated assets at 4.00 percent during 2006. The effective fixed short-term interest rate for 2007 has been set at 4.75 percent.

In addition to application for approval of interim and annual rate changes, the gas utilities may apply from time to time to the BCUC for rate changes to give effect to the changes in costs beyond the control of the utilities.



48



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Important regulatory information, pertaining to decisions made by the BCUC with respect to Terasen Gas Inc., is summarized in the following table.

 

Year ended December 31,

 

2007

 

2006

 

2005

 

2004

 

(Canadian dollar amounts in millions)

Rate Base

$

2,474

 

 

$

2,506

 

 

$

2,306

 

 

$

2,310

 

Deemed Common Equity Component of
Total Capital Structure

 

35.01

%

 

 

35

%

 

 

33

%

 

 

33

%

Allowed Rate of Return on Common Equity

 

8.37

%

 

 

8.80

%

 

 

9.03

%

 

 

9.15

%


Terasen Gas Inc.’s allowed rates of return on common equity (“ROE”) are determined annually based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. On June 30, 2005, Terasen Gas Inc. applied to the BCUC to increase the deemed equity components from 33% to 38%. The application also requested an increase in allowed ROEs from the levels that result from the then current formula, which would have yielded 8.29% for Terasen Gas Inc. in 2006. The BCUC rendered its decision on the application on March 2, 2006, but effective as of January 1, 2006. The generic ROE formula for a benchmark utility in British Columbia was changed such that it will be reset annually from a forecast of 30-year Canada Bonds plus a 3.90% risk premium when the forecast yield on 30-year Canada Bonds is 5.25%. The risk premium is adjusted annually by 75% of the difference between 5.25% and the forecast yield on 30-year Canada Bonds. For 2006, the forecast 30-year Canada Bond yield was 4.79% resulting in a Benchmark ROE for Terasen Gas Inc. of 8.80%, an improvement of 51 basis points over the old formula. In addition, the BCUC increased the deemed equity component for Terasen Gas Inc. to 35% from 33%. For 2007, the allowed ROE for Terasen Gas Inc. is 8.37%.

2004-2007 Performance-Based Rate Plan:  In 2003, Terasen Gas Inc. received BCUC approval of a negotiated settlement of a 2004-2007 Performance-Based Rate Plan (“PBR Settlement”). The PBR Settlement, which took effect January 1, 2004, establishes a process for determining Terasen Gas Inc.’s delivery charges and incentive mechanisms for improved operating efficiencies. The four-year agreement includes incentives for Terasen Gas Inc. to operate more efficiently through sharing of the benefits of cost reductions between Terasen Gas Inc. and its customers. It includes 10 service quality indicators designed to ensure Terasen Gas Inc. provides appropriate service levels and sets out the requirements for an annual review process which will provide a forum for discussion between Terasen Gas Inc. and interested parties regarding its current performance and future activities.

Operation and maintenance costs and base capital expenditures are subject to an incentive formula reflecting increasing costs due to customer growth and inflation, less a productivity factor based on 50% of inflation during the first two years and 66% of inflation during the last two years. Base capital expenditure amounts are a function of customer numbers and projected customer additions. The PBR Settlement provides for a 50/50 customer/shareholder sharing mechanism of earnings above or below the allowed return on equity.

Terasen Gas Inc. has applied for an extension of the 2004-2007 PBR settlement agreement. After an extensive stakeholder consultation process, Terasen Gas Inc. filed an application for approval of a two-year extension to the current 2004-2007 Multi-Year Performance Based Rate Plan. The application requests approval to extend the existing settlement term for 2008-2009. The BCUC has determined that the applications will be reviewed through a written public process throughout February, with a decision expected in March 2007.

Amalgamation of Terasen Gas (Squamish) Inc.:  On November 2, 2006, the government of British Columbia approved the amalgamation of Terasen Gas (Squamish) Inc. (“TGS”) with Terasen Gas Inc. Effective January 1, 2007, natural gas rates charged to TGS customers were aligned with the Terasen Gas Inc. rates. Integration of TGS into Terasen Gas Inc. resulted in changes to regulatory oversight. The BCUC will now have sole authority over the amalgamated company, whereas TGS was regulated through contractual agreements with the province and the BCUC.

Unbundling:  Over the past several years, Terasen Gas Inc., the BCUC and a number of interested parties have laid the groundwork for the introduction of natural gas commodity unbundling. On November 1, 2004, commercial customers of Terasen Gas Inc. became eligible to sign up to buy their natural gas commodity supply directly from third-party suppliers. Terasen Gas Inc. continues to provide delivery of the natural gas. Approximately 79,000 commercial customers are eligible to participate in commodity unbundling. By December 31, 2006, 18,700 customers elected to participate in this program.

During 2006, the BCUC approved offering commodity supply choice to residential customers. The BCUC agreed to open a portion of the province’s residential natural gas market to competition, allowing homeowners to sign long-term fixed price contracts for natural gas with companies other than Terasen Gas Inc. starting in May 2007. Consumers can choose to remain with Terasen Gas Inc. or sign with a marketer, in which case they will begin receiving gas at the marketer’s rate starting in November 2007. Terasen Gas Inc. will continue to provide delivery service to unbundled customers and delivery margins are not expected to be impacted by migration of residential customers to alternative commodity suppliers.



49



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



TGVI

The Province of British Columbia and TGVI’s previous parent company entered into the Vancouver Island Natural Gas Pipeline Agreement (the “VINGPA”) to restructure the financial arrangements relating to TGVI’s pipeline and connected distribution systems. Under the VINGPA, the Province agreed to make quarterly payments from 1996 through 2011 related to natural gas production royalties associated with deemed volumes of natural gas transported through the Vancouver Island pipeline. The royalty related payment recognized in 2006 was C$36.3 million. Under the VINGPA, TGVI’s parent company agreed to provide future financial support of up to C$120 million over the period from 1996 to 2011 and C$17.5 million for 1995 to finance the principal amount of the revenue deficiencies incurred by TGVI. Annual revenue deficiencies were calculated as the difference between the regulated allowed return on approved rate base and earnings actually derived from sales revenues and expenses. The accumulated revenue deficiency resulting from overall revenues being below the cost of service had been recorded in a Revenue Deficiency Deferral Account (“RDDA”).

When Terasen acquired TGVI, the amount of the RDDA was C$85 million, for which Terasen paid a price of C$61 million. The accumulated RDDA totaled C$30.9 million at December 31, 2006, corresponding to a balance for TGVI regulatory purposes of C$41.4 million, down C$4.3 million from December 31, 2005. Terasen is committed to fund any increases in revenue deficiencies by purchasing preferred shares or subordinated debt issued by TGVI. The BCUC was directed to set rates beginning in 2003 that amortize the RDDA balance over the shortest period reasonably possible, having regard for TGVI’s competitive position relative to alternative energy sources and the desirability of reasonable rates. As part of the acquisition of TGVI, Terasen assumed the rights and obligations of TGVI’s previous parent company under the VINGPA.

TGVI’s distribution rates are set by the BCUC in accordance with regulatory principles generally applied by the BCUC to natural gas utilities operating within British Columbia. On November 30, 2005, TGVI received BCUC approval for a new regulatory settlement, which took effect January 1, 2006. The 2006-2007 settlement provides for a continuation of operation and maintenance cost incentive arrangements previously in place. As noted above, on March 2, 2006, the BCUC issued its Decision on the ROE application. In the Decision, TGVI’s request for an increase in its deemed equity components from 35% to 40% was approved. The Decision also resulted in an improvement in its allowed ROE to 70 basis points over the Benchmark ROE to 9.50% to be effective January 1, 2006. Due to a decline in the forecast benchmark 30-year Canada Bond, the allowed ROE has been set at 9.07% for 2007.

TGVI has applied for an extension of its settlement agreement which expires at the end of 2007. After an extensive stakeholder consultation process, TGVI filed an application for approval of a two-year extension to the current 2006-2007 Negotiated Settlement Agreement. The BCUC has determined that the application will be reviewed through a written public process throughout February/March, with a decision expected in March 2007.

Kinder Morgan Canada

Trans Mountain

The Canadian portion of the crude oil and refined product pipeline system is under the regulatory jurisdiction of 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 CAPP and principal shippers for a new Incentive Toll Settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010 (the “2006 ITS”). In January 2006, Trans Mountain reached agreement in principle reduced to a memorandum of understanding for the 2006 ITS. A final agreement was reached with CAPP in October 2006 and NEB approval was received in November 2006. The 2006 ITS 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 revenue generated by throughput in excess of 92.5% of the capacity of the pipeline. The 2006 ITS provides for base tolls which will, other than recalculation or adjustment in certain specified circumstances, remain in effect for the five-year period. The 2006 ITS also governs the financial arrangements for the approximately C$638 million in planned expansions to Trans Mountain that will add 75,000 bpd of incremental capacity to the system by late 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” preceding.

Corridor

As an intra-provincial pipeline system, Corridor is subject to the jurisdiction of the Alberta Energy and Utilities Board (“AEUB”). With respect to Corridor, matters such as rates of return, construction and operation of facilities and tolls are



50



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



governed by contractual arrangements with shippers and are subject to regulation by the AEUB. The Firm Service Agreement (“FSA”), which was effective, from a tolling perspective, with the commencement of commercial operations on May 1, 2003, sets pipeline tolls based on cost of service mechanisms. Shell and its partners have made a 25-year take or pay commitment under the FSA to transport a total of 150,000 bpd of bitumen and 65,000 bpd of diluent in the Corridor Pipeline.

Express

The Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2 pipeline, which results in rates and terms of service being regulated on a complaint basis only. The U.S. segment of the Express Pipeline and the Platte Pipeline are regulated by the FERC, which regulates the rates and terms of service of a common carrier. The FERC has additionally established methods by which pipelines may increase their rates.

Express committed rates are subject to a 2% inflation adjustment April 1 of each year. Uncommitted or ceiling rates for both the U.S. segment of Express Pipeline and Platte Pipeline are subject to adjustment in accordance with the FERC’s annual indexing formula. Platte has historically been unable to charge its ceiling rates and has had to discount its rates because of market fundamentals in PADD II. With changes in market conditions over the past year, Platte has been able to successfully remove all of its discounts. Today, all rates on Platte are at the applicable ceiling level.

Additionally, movements on the Platte Pipeline within the State of Wyoming are regulated by the Wyoming Public Service Commission (“WPSC”), which regulates the tariffs and terms of service of public utilities that operate in the State of Wyoming. The WPSC standards applicable to rates are similar to those of the FERC and the NEB.

Safety Regulation

Our interstate pipelines are subject to regulation by the United States Department of Transportation and our intrastate pipelines and other operations are subject to comparable state regulations with respect to their design, installation, testing, construction, operation, replacement and management. We must permit access to and copying of records, and make certain reports and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which we conduct pipeline operations. In addition, our truck and terminal loading facilities are subject to U.S. DOT regulations dealing with the transportation of hazardous materials by motor vehicles and railcars. We believe that we are in substantial compliance with U.S. DOT and comparable state regulations.

The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of testing, education, training and communication. The Pipeline Safety Act requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas that are designated as High Consequence Areas. Pipeline companies are required to perform the integrity tests within ten years of the date of enactment and must perform subsequent integrity tests on a seven year cycle. At least 50% of the highest risk segments must be tested within five years of the enactment date. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal magnetic flux or ultrasonic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained, and the U.S. DOT has approved our qualification program. We believe that we are in substantial compliance with this law’s requirements and have integrated appropriate aspects of this pipeline safety law into our internal Operator Qualification Program. A similar integrity management rule for refined petroleum products pipelines became effective May 29, 2001. All baseline assessments for products pipelines must be completed by March 31, 2008. We expect to meet the required deadlines for both our natural gas and refined petroleum products pipelines.

Certain of our products pipelines have been issued orders and civil penalties by the U.S. DOT’s Office of Pipeline Safety concerning alleged violations of certain federal regulations concerning our products pipeline integrity management program. However, we dispute some of the Office of Pipeline Safety findings and disagree that civil penalties are appropriate for them, and we therefore requested an administrative hearing on these matters according to the U.S. DOT regulations. Information on these matters is more fully described in Note 19 to our consolidated financial statements.

On March 25, 2003, the U.S. DOT issued their final rules on Hazardous Materials: Security Requirements for Offerors and Transporters of Hazardous Materials. We believe that we are in substantial compliance with these rules and have made revisions to our Facility Security Plan to remain consistent with the requirements of these rules.

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

In general, we expect to increase expenditures in the future to comply with higher industry and regulatory safety standards. Some of these changes, such as U.S. DOT implementation of additional hydrostatic testing requirements, could significantly



51



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



increase the amount of these expenditures. Such expenditures cannot be accurately estimated at this time.

State, Provincial and Local Regulation

Our activities are subject to various state, provincial 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 extensive and evolving federal, provincial, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements, issuance of injunction as to future compliance or other mandatory or consensual measures. We have an ongoing environmental compliance program. However, risks of accidental leaks or spills are associated with the transportation and storage of natural gas liquids, refined petroleum products, natural gas and carbon dioxide, the handling and storage of liquid and bulk materials and the other activities conducted by us. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our businesses. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 35 years, and we anticipate that there will be continuing changes. One trend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants, generation and disposal of wastes and use, storage and handling of chemical substances that may impact human health and safety or the environment. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such change, or that our efforts will prevent material costs, if any, from arising.

We are currently involved in environmentally related legal proceedings and clean up activities. Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters will not have a material adverse effect on our business, financial position or results of operations. We have accrued an environmental reserve in the amount of $77.8 million as of December 31, 2006. Our reserve estimates range in value from approximately $77.8 million to approximately $130.7 million, and we have recorded a liability equal to the low end of the range. For additional information related to environmental matters, see Note 19 to our consolidated financial statements included elsewhere in this report.

Solid Waste

We own numerous properties that have been used for many years for the production of crude oil, natural gas and carbon dioxide, the transportation and storage of refined petroleum products and natural gas liquids and the handling and storage of coal and other liquid and bulk materials. Virtually all of these properties were owned by others before us. Solid waste disposal practices within the petroleum industry have changed over the years with the passage and implementation of various environmental laws and regulations. Hydrocarbons and other solid wastes may have been disposed of in, on or under various properties owned by us during the operating history of the facilities located on such properties. Virtually all of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other solid wastes was not under our control. In such cases, hydrocarbons and other solid wastes could migrate from the facilities and have an adverse effect on soils and groundwater. We maintain a reserve to account for the costs of cleanup at sites known to have surface or subsurface contamination requiring response action.

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



52



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



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 of 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 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. The Illinois Environmental Protection Agency and the Texas Natural Resource Conservation Commission have proposed regulations that would require reduction of emissions of nitrogen oxides from internal combustion engines. These regulations could result in additional capital expenditures related to installation of emission controls on several compressor engines in each state. However, while additional capital expenditures may be necessary to comply with these regulations, we do not believe that we will be materially adversely impacted by these proposed regulations.

Due to the broad scope and complexity of the issues involved and the resultant complexity and nature of the regulations, full development and implementation of many Clean Air Act regulations by the U.S. EPA and/or various state and local regulators have been delayed. Therefore, until such time as the new Clean Air Act requirements are implemented, we are unable to fully estimate the effect on earnings or operations or the amount and timing of such required capital expenditures. At this time, however, we do not believe that we will be materially adversely affected by any such requirements.

Clean Water Act

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

EPA Fuel Specifications/Gasoline Volatility Restrictions

In order to control air pollution in the United States, the U.S. EPA has adopted regulations that require the vapor pressure of motor gasoline sold in the United States to be reduced from May through mid-September of each year. These regulations mandated vapor pressure reductions beginning in 1989, with more stringent restrictions beginning in 1992. States may impose additional volatility restrictions. The regulations have had a substantial effect on the market price and demand for normal butane, and to some extent isobutane, in the United States. Gasoline manufacturers use butanes in the production of motor gasolines. Since normal butane is highly volatile, it is now less desirable for use in blended gasolines sold during the summer months. Although the U.S. EPA regulations have reduced demand and may have contributed to a significant decrease in prices for normal butane, low normal butane prices have not impacted our pipeline business in the same way they would impact a business with commodity price risk. The U.S. EPA regulations have presented the opportunity for additional transportation services on portions of our liquids pipeline systems, for example, our North System. In the summer of 1991, our North System began long-haul transportation of refinery grade normal butane produced in the Chicago area to the Bushton, Kansas area for storage and subsequent transportation north from Bushton during the winter gasoline blending season. That service continues, and we also provide transportation and storage of butane from the Chicago area back to Bushton during the summer season.



53



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



Methyl Tertiary-Butyl Ether

Methyl tertiary-butyl ether, referred to in this report as MTBE, is commonly used as an additive in gasoline. It is manufactured by chemically combining a portion of petrochemical production with purchased methanol and is widely used as an oxygenate blended with gasoline to reduce emissions. Due to environmental and health concerns, California mandated the elimination of MTBE from gasoline by January 1, 2004. With certain scientific studies showing that MTBE was having a detrimental effect on water supplies, a number of other states are making moves to ban MTBE also. Although various drafts of The Energy Policy Act of 2005 provided for the gradual phase out of the use of MTBE, the final bill did not include that provision. Instead, the Act eliminated the oxygenate requirement for reformulated gasoline but did not ban the use of MTBE. So, it is likely that the use of MTBE will be phased out through state bans and voluntary shifts to different formulations of gasoline by the refiners.

In California and other states, MTBE-blended gasoline has been banned from use or may be replaced by an ethanol blend. However, due to the lack of dedicated pipelines, ethanol cannot be shipped through pipelines and therefore, we have realized some reduction in California gasoline volumes transported by our Pacific operations’ pipelines. However, the conversion from MTBE to ethanol in California has resulted in an increase in ethanol blending services at many of our refined petroleum products terminal facilities, and the fees we earn for ethanol-related services at our terminals more than offset the reduction in pipeline transportation fees. Furthermore, we have aggressively pursued additional ethanol opportunities in other states where MTBE has been banned or where our customers have decided not to market MTBE gasoline.

Our role in conjunction with ethanol is proving beneficial to our various business segments as follows:

·

our Products Pipelines’ terminals are storing and blending ethanol because unlike MTBE, it cannot flow through refined petroleum products pipelines;

·

our Natural Gas Pipelines segment is delivering natural gas through our pipelines to service new ethanol plants that are being constructed in the Midwest (natural gas is the feedstock for ethanol plants); and

·

our Terminals segment is entering into liquid storage agreements for ethanol around the country, in such areas as Houston, Chicago, Nebraska and on the East Coast.

Safety and Environmental Protection

Our senior executives are committed to ensuring that we are an industry leader with respect to environmental protection and compliance with environmental policies. Health, safety and environmental issues and initiatives are reported regularly to our senior executives.

Terasen Gas Inc. and Kinder Morgan Canada have been active participants in Canada’s Voluntary Climate Change Challenge and Registry, which is now referred to as the Canadian Standards Association Canadian Greenhouse Gas Challenge Registry (“VCR”). For the seventh consecutive year, Terasen Gas Inc. received gold level reporting status from VCR in recognition of its efforts to manage and reduce greenhouse gas emissions. Terasen Gas Inc. received the VCR Leadership award in 2001 and 2003, becoming the only company in its sector to have received the honor twice. The VCR ranking acknowledges Terasen Gas Inc.’s efforts to develop specific measures and voluntarily set reduction targets. Kinder Morgan Canada has achieved a silver level with VCR for the past three years and has registered to participate in the American Petroleum Institute’s voluntary program in the United States.

Since mandatory Environment Canada greenhouse gas reporting regulations have been implemented on facilities with reportable annual emissions exceeding 100,000 metric tons of CO2 equivalent per year, in 2006 Terasen Gas Inc. reported approximately 102,000 metric tons of CO2 equivalent for 2005 emissions.

We have detailed emergency preparedness plans in place to respond to natural disasters, accidents and emergencies, and regularly test these plans in simulations involving employees and other emergency response organizations. The Company is also committed to monitor and assess its safety and environmental performance regularly. We incorporate safety performance measures into our employee compensation system, set targets and objectives for environmental performance, and conduct safety and environmental audits.

Other

Amounts we spent during 2006, 2005, and 2004 on research and development activities were not material. We employed 8,602 people at December 31, 2006, including employees of our indirect subsidiary KMGP Services Company, Inc., who are dedicated to the operations of Kinder Morgan Energy Partners.



54



Items 1. and 2.

Business and Properties. (continued)

KMI Form 10-K



KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan Management, provides centralized payroll and employee benefits services to Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy Partners’ operating partnerships and subsidiaries (collectively, “the Group”). Employees of KMGP Services Company, Inc. are assigned to work for one or more members of the Group. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse their allocated shares of these direct costs. No profit or margin is charged by Kinder Morgan Services LLC to the members of the Group. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to the limited partnership agreement, Kinder Morgan Energy Partners provides reimbursement for its share of these administrative costs and such reimbursements are accounted for as described above. Kinder Morgan Energy Partners reimburses Kinder Morgan Management with respect to the costs incurred or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy Partners’ limited partnership agreement, the Delegation of Control Agreement among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners and others, and Kinder Morgan Management’s limited liability company agreement.

Our named executive officers and other employees that provide management or services to both us and the Group are employed by us. Additionally, other of our employees assist Kinder Morgan Energy Partners in the operation of its Natural Gas Pipeline assets. These employees’ expenses are allocated without a profit component between us and the appropriate members of the Group.

We are of the opinion that, with only insignificant exceptions, we have satisfactory title to the properties owned and used in our businesses, subject to the liens for current taxes, liens incidental to minor encumbrances, and easements and restrictions which do not materially detract from the value of such property or the interests therein or the use of the 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.

(D) Financial Information about Geographic Areas

Note 17 of the accompanying Notes to Consolidated Financial Statements contains financial information about the geographic areas in which we do business.

(E) Available Information

We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Also, we make available free of charge within the “Investors” section of our internet website, at www.kindermorgan.com, and in print to any shareholder who requests, our governance guidelines, the charters of our audit committee, compensation committee and nominating and governance committee, and our code of business conduct and ethics (which applies to our senior financial officers and chief executive officer, among others). Requests for copies may be directed to Investor Relations, Kinder Morgan, Inc., 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We intend to disclose any amendments to our code of business conduct and ethics, and any waiver from a provision of that code granted to our Chief Executive Officer, Chief Financial Officer or Vice President and Controller, on our internet website within four business days following such amendment or waiver. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the Securities and Exchange Commission.

Item 1A.

Risk Factors.

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Failure to complete the proposed transaction that would take us private would likely have an adverse effect on us. There can be no assurance that the conditions to the completion of the merger under which investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, would acquire all of our outstanding common stock (except for shares held by certain stockholders and investors), referred to as the “Going Private” transaction, will be satisfied. In connection with the Going Private transaction, we are subject to several risks, including the following:



55



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



On May 26, 2006, the last trading day prior to the announcement of management’s proposal of the merger, our common stock closed at $84.41 per share. After that announcement, the stock price rose to trade close to the $100 per share proposal price. Since the merger agreement was signed on August 28, 2006, our common stock has traded generally between $104 and $106 per share. The current price of our common stock may reflect a market assumption that the merger will close. If the merger is not consummated, the stock price would likely retreat from its current trading range.

·

Certain costs relating to the merger, including legal, accounting and financial advisory fees, are payable by us whether or not the merger is completed.

·

Under circumstances set out in the merger agreement, if the Going Private transaction is not completed we may be required to pay the acquiring company a termination fee of $215 million and reimburse up to $45 million of the acquiring company’s expenses, which will be credited against the termination fee if it becomes payable.

·

Our management’s and our employees’ attention will have been diverted from our day-to-day operations, we may experience unusually high employee attrition and our business and customer relationships may be disrupted.

Consummation of the Going Private transaction would result in substantially more debt to us, which could have an adverse effect on us, such as a downgrade of the ratings of our debt securities, which would increase our cost of capital. In response to the May 29, 2006 announcement of the proposal to acquire all of our outstanding common stock, Moody’s Investor Services placed both our long-term and short-term debt ratings under review for possible downgrade. On January 5, 2007, after we announced shareholder approval of the Going Private transaction, our debt rating was downgraded by Standard & Poor’s to BB- with the anticipated increase in debt that would result if the Going Private transaction is consummated. This factor, combined with the uncertainty that the Going Private transaction or any other proposals or extraordinary transaction will be approved or completed, has limited our access to the commercial paper market. As a result, we are currently utilizing our $800 million credit facility for our short-term borrowing needs. Such uncertainty could also increase our cost of borrowing in the capital markets.

Our substantially increased debt as a result of the Terasen acquisition could adversely affect our financial health and make us more vulnerable to adverse economic conditions. As a result of our acquisition of Terasen, we have significantly more debt outstanding and significantly higher debt service requirements than in the recent past. As of December 31, 2006, we had outstanding approximately $12.8 billion of consolidated debt (excluding Deferrable Interest Debentures Issued to Subsidiary Trusts and Capital Securities). Of this amount, $5.7 billion and $2.4 billion was debt of our subsidiaries of Kinder Morgan Energy Partners and Terasen, Inc., respectively, including their subsidiaries.

Our increased level of debt could have important consequences, such as:

·

limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes;

·

limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt;

·

placing us at a competitive disadvantage compared to competitors with less debt; and

·

increasing our vulnerability to adverse economic and industry conditions.

Each of these factors is to a large extent dependent on economic, financial, competitive and other factors beyond our control.

Our large amount of floating rate debt makes us vulnerable to increases in interest rates. As of December 31, 2006, we had outstanding approximately $12.8 billion of consolidated debt. Of this amount, excluding debt of Kinder Morgan Energy Partners that is consolidated as a result of EITF No. 04-5, approximately 50% was subject to floating interest rates, either as short-term commercial paper or as long-term fixed-rate debt converted to floating rates through the use of interest rate swaps. Should interest rates increase significantly, our cash available to service our debt would be adversely affected.

Kinder Morgan Energy Partners could be treated as a corporation for United States income tax purposes. Kinder Morgan Energy Partners’ treatment as a corporation would substantially reduce the cash distributions on the common units that it distributes quarterly. The anticipated benefit of our investment in Kinder Morgan Energy Partners depends largely on its treatment as a partnership for federal income tax purposes. Kinder Morgan Energy Partners has not requested, and does not plan to request, a ruling from the Internal Revenue Service on this or any other matter affecting Kinder Morgan Energy Partners. Current law requires Kinder Morgan Energy Partners to derive at least 90% of its annual gross income from specific



56



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



activities to continue to be treated as a partnership for federal income tax purposes. Kinder Morgan Energy Partners may not find it possible, regardless of its efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. Current law may change so as to cause Kinder Morgan Energy Partners to be treated as a corporation for federal income tax purposes without regard to its sources of income or otherwise subject it to entity-level taxation.

If Kinder Morgan Energy Partners was to be treated as a corporation for federal income tax purposes, it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Under current law, distributions to unitholders, including us, would generally be taxed as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy Partners as a corporation, the cash available for distribution to its unitholders, including us, would be substantially reduced.

In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon Kinder Morgan Energy Partners as an entity, the cash available for distribution to its unitholders would be reduced.

Competition could ultimately lead to lower levels of profits and adversely impact our ability to recontract for expiring transportation capacity at favorable rates. For the year ended December 31, 2006, NGPL’s segment earnings represented approximately 32% of our total segment earnings plus net pre-tax impact of Kinder Morgan Energy Partners. NGPL is an interstate natural gas pipeline that is a major supplier to the Chicago, Illinois area. In the past, interstate pipeline competitors of NGPL have constructed or expanded pipeline capacity into the Chicago area. To the extent that an excess of supply into this market area is created and persists, NGPL’s ability to recontract for expiring transportation capacity at favorable rates could be impaired. Contracts representing approximately 6.3% of NGPL’s total long-haul, contracted firm transport capacity as of January 31, 2007 have not been renewed and are scheduled to expire before the end of 2007.

Trans Mountain’s pipeline to the West Coast of North America and the Express System, in which we own an interest, to the U.S. Rocky Mountains and Midwest are two of several pipeline alternatives for Western Canadian petroleum production. These pipelines, like all our petroleum pipelines, compete 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.

Because electricity prices in British Columbia continue to be set based on the historical average cost of production, rather than based on market forces, they have remained artificially low compared to market-priced electricity and, as a result, only marginally higher than comparable, market-based natural gas costs. A sustained increase in natural gas commodity prices could cause natural gas in British Columbia to be uncompetitive with electricity, thereby decreasing the use of natural gas by Terasen Gas’ customers.

The rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers on our natural gas pipeline systems and the rates our natural gas distribution operations can charge are subject to regulatory approval and oversight. While there are currently no material proceedings challenging the rates on any of our natural gas pipeline systems, regulators and shippers on these pipelines do have rights to challenge the rates they are charged under certain circumstances prescribed by applicable regulations. We can provide no assurance that we will not face challenges to the rates we receive on our pipeline systems in the future. Any successful challenge could materially adversely affect our future earnings and cash flows.

As part of the establishment of the rates which gas distribution operations can charge their customers, utility regulators, including the British Columbia Utilities Commission, or BCUC, generally establish a rate base and a reasonable and fair return for the utility upon that rate base. The allowed rates of return on our gas distribution operations are calculated differently and vary in amount in different jurisdictions. In British Columbia, the allowed rates of return on equity are determined annually by the BCUC based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. The allowed returns on equity for Terasen Gas Inc. and TGVI are determined by formulae that result in lower allowed returns on equity if long-term Government of Canada bond yields decline. Most rates in British Columbia are established using a future test year which has forecasts of the volume of gas that will be sold and transported and the costs, including the rate of return, that the utility will incur with cost and revenue tracking and sharing mechanisms that result in annual rate adjustments. Terasen Gas Inc. and TGVI have performance-based rate agreements expiring in 2007. There can be no assurance that new rate agreements will be entered into or that the regulatory process in which rates are determined will always produce rates that will result in full recovery of our British Columbia gas distribution operation’s costs.

Pending Federal Energy Regulatory Commission and California Public Utilities Commission proceedings seek substantial refunds and reductions in tariff rates on some of Kinder Morgan Energy Partners’ pipelines. If the proceedings are determined adversely to us, they could have a material adverse impact on us. Regulators and shippers on our pipelines have rights to challenge the rates Kinder Morgan Energy Partners charges under certain circumstances prescribed by applicable regulations. Some shippers on Kinder Morgan Energy Partners’ pipelines have filed complaints with the Federal Energy Regulatory Commission and California Public Utilities Commission that seek substantial refunds for alleged overcharges during



57



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



the years in question and prospective reductions in the tariff rates on Kinder Morgan Energy Partners’ Pacific operations’ pipeline system. Kinder Morgan Energy Partners may face challenges, similar to those described in Note 19 to our consolidated financial statements included elsewhere in this report, to the rates it receives on its pipelines in the future. Any successful challenge could adversely and materially affect our future earnings and cash flows.

Sustained periods of weather inconsistent with normal in areas served by our natural gas distribution operations can create volatility in our earnings. Our operating results may fluctuate on a seasonal basis. Weather-related factors such as temperature and rainfall at certain times of the year affect our earnings, principally in our retail natural gas distribution business. Sustained periods of temperatures and rainfall that differ from normal can create volatility in our earnings. In many areas, natural gas consumption patterns peak in the winter, especially for our retail natural gas distribution operations. Those operations normally generate higher net earnings in the first and fourth quarters, which are offset to some extent by lower earnings or net losses in the second and third quarters.

Proposed rulemaking by the FERC, the BCUC, the NEB or other regulatory agencies having jurisdiction could adversely impact our income and operations. Generally speaking, new laws or regulations or different interpretations of existing laws or regulations applicable to our assets could have a negative impact on our business, financial condition and results of operations.

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 Kinder Morgan Energy Partners’ approximate $4.4 billion Rockies Express Pipeline and approximate $1.25 billion Midcontinent Express Pipeline. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors, may result in increased costs or delays in construction. Cost overruns or delays in completing a project could have an adverse effect on our results of operations and cash flows.

Our rapid growth may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions. Part of our business strategy includes acquiring additional businesses, expanding existing assets, or constructing new facilities. If we do not successfully integrate acquisitions, expansions, or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including:

·

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.

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 damages, compensate for human exposure or property damage, install costly pollution control equipment, or a combination of these and other measures. The resulting costs and liabilities could negatively affect our level of earnings and cash flow. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities. The impact of environmental standards or future environmental measures could increase our costs significantly. 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.



58



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



We own or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where such wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, use and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed thereon may be subject to laws in the United States such as the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, which impose joint and several liability without regard to fault or the legality of the original conduct. Under the regulatory schemes of the various provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

In addition, Kinder Morgan Energy Partners’ 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, Kinder Morgan Energy Partners is subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. The costs of environmental regulation are already significant, and additional or more stringent regulation could increase these costs or could otherwise negatively affect our business.

Current or future distressed financial condition of customers could have an adverse impact on our operations in the event these customers are unable to pay us for the products or services we provide. Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their credit worthiness. 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.

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. 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 could significantly increase the amount of these expenditures.

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 its 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



59



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



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 Terasen, a significant 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 stockholders’ equity under applicable accounting rules.

The future success of Kinder Morgan Energy Partners’ oil and gas development and production operations depends in part upon its ability to develop additional oil and gas reserves that are economically recoverable. The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves and revenues of Kinder Morgan Energy Partners’ CO2 business segment will decline. Kinder Morgan Energy Partners may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future.

The development of oil and gas properties involves risks that may result in a total loss of investment. The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well, or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

The volatility of natural gas and oil prices could have a material adverse effect on our business. The revenues, profitability and future growth of Kinder Morgan Energy Partners’ CO2 business segment and the carrying value of its 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 Kinder Morgan Energy Partners’ proved reserves. In the event prices fall substantially, Kinder Morgan Energy Partners may not be able to realize a profit from its production and would operate at a loss. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.

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

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and floating interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage



60



Item 1A.

Risk Factors. (continued)

KMI Form 10-K



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.

Item 1B.

Unresolved Staff Comments.

None.

Item 3.

Legal Proceedings.

The reader is directed to Note 19 of the accompanying Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Item 4.

Submission of Matters to a Vote of Security Holders.

We held a special meeting of shareholders on December 19, 2006 to vote on a proposal to approve and adopt the Agreement and Plan of Merger among Kinder Morgan, Inc., Knight Holdco LLC and Knight Acquisition Co., as it may be amended from time to time. The matter was unanimously approved and recommended by our board of directors (with the three directors who are participating as rollover investors in the transaction contemplated in the merger agreement taking no part in the deliberations).

With respect to the proposal, the vote was as follows:

For

97,275,863

Against

1,827,306

Abstain

916,573

Broker Non-votes

N/A


This proposal was approved as it received the affirmative vote of the holders of at least two-thirds of all our common stock entitled to vote at the special meeting.



61



KMI Form 10-K



PART II

Item 5.

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

Our common stock is listed for trading on the New York Stock Exchange under the symbol “KMI.” Dividends paid and the high and low sale prices per share, as reported on the New York Stock Exchange, of our common stock by quarter for the last two years are provided below. In January 2006, we increased our quarterly common dividend to $0.875 per share.

  

 

Market Price Per Share

  

 

2006

 

2005

  

 

Low

 

High

 

Low

 

High

  

Quarter Ended:

 

 

 

 

 

 

 

  

March 31

$89.13

 

$103.75

 

$69.27

 

$81.57

  

June 30

$81.00

 

$103.00

 

$72.49

 

$83.97

  

September 30

$99.50

 

$105.00

 

$81.82

 

$99.97

  

December 31

$104.00

 

$106.20

 

$84.10

 

$96.28

  

  

 

Dividends Paid Per Share

 

 

2006

 

2005

  

Quarter Ended:

 

 

 

  

March 31

$0.8750

 

$0.7000

  

June 30

$0.8750

 

$0.7000

  

September 30

$0.8750

 

$0.7500

  

December 31

$0.8750

 

$0.7500

  

  

 

 

 

  

Stockholders as of February 1, 2007

71,000 (approximately)


There were no sales of unregistered equity securities during the period covered by this report.

For information regarding our equity compensation plans, please refer to Item 12, included elsewhere herein.

Our Purchases of Our Common Stock

Period

Total Number of

Shares Purchased1

Average Price

Paid per Share

Total Number of

Shares Purchased as

Part of Publicly

Announced Plans

or Programs1

Maximum Number (or

Approximate Dollar

Value) of Shares that May

Yet Be Purchased Under

the Plans or Programs

October 1 to
October 31, 2006

 

-

 

 

$

-

 

 

-

 

 

$

18,203,665

 

November 1 to
November 30, 2006

 

-

 

 

$

-

 

 

-

 

 

$

18,203,665

 

December 1 to
December 31, 2006

 

-

 

 

$

-

 

 

-

 

 

$

18,203,665

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

-

 

 

$

-

 

 

-

 

 

$

18,203,665

 

  

1

On August 14, 2001, we announced a plan to repurchase $300 million of our outstanding common stock, which program was increased to $400 million, $450 million, $500 million, $550 million, $750 million, $800 million and $925 million in February 2002, July 2002, November 2003, April 2004, November 2004, April 2005 and November 2005, respectively.

  










62



KMI Form 10-K



Item 6.

Selected Financial Data.

Five-Year Review1

Kinder Morgan, Inc. and Subsidiaries

 

Year Ended December 31,

 

20062,3,4

 

20053

 

2004

 

2003

 

2002

 

(In millions except per share amounts)

Operating Revenues

$

11,846.4

 

 

$

1,254.5

 

 

$

877.7

 

 

$

848.8

 

 

$

755.5

 

Gas Purchases and Other Costs of Sales

 

7,318.1

 

 

 

458.8

 

 

 

194.2

 

 

 

232.1

 

 

 

164.7

 

Other Operating Expenses5

 

3,142.1

 

 

 

371.8

 

 

 

342.5

 

 

 

316.5

 

 

 

397.8

 

Operating Income

 

1,386.2

 

 

 

423.9

 

 

 

341.0

 

 

 

300.2

 

 

 

193.0

 

Other Income and (Expenses)

 

(1,063.4

)

 

 

451.5

 

 

 

365.2

 

 

 

281.5

 

 

 

214.4

 

Income from Continuing Operations
Before Income Taxes

 

322.8

 

 

 

875.4

 

 

 

706.2

 

 

 

581.7

 

 

 

407.4

 

Income Taxes

 

274.1

 

 

 

345.5

 

 

 

208.0

 

 

 

225.1

 

 

 

121.8

 

Income from Continuing Operations

 

48.7

 

 

 

529.9

 

 

 

498.2

 

 

 

356.6

 

 

 

285.6

 

Gain (Loss) from Discontinued Operations,
Net of Tax

 

23.2

 

 

 

24.7

 

 

 

23.9

 

 

 

25.1

 

 

 

17.1

 

Net Income

$

71.9

 

 

$

554.6

 

 

$

522.1

 

 

$

381.7

 

 

$

302.7

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic Earnings (Loss) Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

$

0.37

 

 

$

4.29

 

 

$

4.03

 

 

$

2.91

 

 

$

2.34

 

Discontinued Operations

 

0.17

 

 

 

0.20

 

 

 

0.19

 

 

 

0.20

 

 

 

0.14

 

Total Basic Earnings Per Common Share

 

0.54

 

 

$

4.49

 

 

$

4.22

 

 

$

3.11

 

 

$

2.48

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Shares Used in Computing Basic Earnings (Loss) Per Common Share

 

133.0

 

 

 

123.5

 

 

 

123.8

 

 

 

122.6

 

 

 

122.2

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted Earnings (Loss) Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Continuing Operations

$

0.36

 

 

$

4.25

 

 

$

3.99

 

 

$

2.88

 

 

$

2.31

 

Discontinued Operations

 

0.17

 

 

 

0.20

 

 

 

0.19

 

 

 

0.20

 

 

 

0.14

 

Total Diluted Earnings Per Common Share

$

0.53

 

 

$

4.45

 

 

$

4.18

 

 

$

3.08

 

 

$

2.45

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Shares Used in Computing Diluted Earnings (Loss) Per Common Share

 

135.0

 

 

 

124.6

 

 

 

124.9

 

 

 

123.8

 

 

 

123.4

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends Per Common Share

$

3.50

 

 

$

2.90

 

 

$

2.25

 

 

$

1.10

 

 

$

0.30

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Expenditures6

 

1,583.1

 

 

$

144.5

 

 

$

103.2

 

 

$

132.0

 

 

$

149.6

 

  

1

Includes significant impacts from acquisitions and dispositions of assets. See Notes 1(Q), 4 and 5 of the accompanying Notes to Consolidated Financial Statements for information regarding dispositions during 2006, 2005, and 2004.

2

Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investments in Kinder Morgan Energy Partners. See Note 1(B) of the accompanying Notes to Consolidated Financial Statements.

3

Includes the results of Terasen Inc. subsequent to its November 30, 2005 acquisition by us. See Note 4 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.

4

Includes results of operations for the oil and gas properties acquired by Kinder Morgan Energy Partners from Journey Acquisition-I, L.P. and Journey 2000, L.P., the terminal assets and operations acquired by Kinder Morgan Energy Partners 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. Kinder Morgan Energy Partners acquired all of the membership interests in Transload Services, LLC effective November 20, 2006, and they acquired all of the membership interests in Devco USA L.L.C. effective December 1, 2006. Kinder Morgan Energy Partners also acquired a 66 2/3% ownership interest in Entrega Pipeline LLC effective February 23, 2006, however, its earnings were not materially impacted during 2006 due to the fact that regulatory accounting provisions required capitalization of revenues and expenses until the second segment of the Entrega Pipeline is complete and in-service.

5

Includes a charge of $650.5 million in 2006 to reduce the carrying value of Terasen Gas. Also includes charges of $1.2 million, $6.5 million, $33.5 million, $44.5 million and $134.5 million in 2006, 2005, 2004, 2003 and 2002, respectively, to reduce the carrying value of certain power assets; see Note 6 of the accompanying Notes to Consolidated Financial Statements.

6

Capital Expenditures shown are for continuing operations only.



63



Item 6.

Selected Financial Data. (continued)

KMI Form 10-K



Five-Year Review (Continued)

Kinder Morgan, Inc. and Subsidiaries

 

As of December 31,

 

20061,2

 

 

20052

 

 

2004

 

 

2003

 

 

2002

 

 

 

(In millions except per share amounts)

Total Assets

$

26,795.6

 

 

 

 

$

17,451.6

 

 

 

 

$

10,116.9

 

 

 

 

$

10,036.7

 

 

 

 

$

10,102.8

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Equity3

$

3,657.5

 

20

%

 

$

4,051.4

 

34

%

 

$

2,919.5

 

45

%

 

$

2,691.8

 

39

%

 

$

2,399.7

 

37

%

Deferrable Interest
Debentures
4

 

283.6

 

2

%

 

 

283.6

 

2

%

 

 

283.6

 

4

%

 

 

283.6

 

4

%

 

 

-

 

-

 

Capital Securities

 

106.9

 

1

%

 

 

107.1

 

1

%

 

 

-

 

-

 

 

 

-

 

-

 

 

 

-

 

-

 

Preferred Capital
Trust Securities
4

 

-

 

-

 

 

 

-

 

-

 

 

 

-

 

-

 

 

 

-

 

-

 

 

 

275.0

 

4

%

Minority Interests

 

3,095.5

 

17

%

 

 

1,247.3

 

10

%

 

 

1,105.4

 

17

%

 

 

1,010.1

 

15

%

 

 

967.8

 

15

%

Outstanding Notes
and Debentures
5

 

10,623.9

 

60

%

 

 

6,286.8

 

53

%

 

 

2,258.0

 

34

%

 

 

2,837.5

 

42

%

 

 

2,852.2

 

44

%

Total Capitalization

$

17,767.4

 

100

%

 

$

11,976.2

 

100

%

 

$

6,566.5

 

100

%

 

$

6,823.0

 

100

%

 

$

6,494.7

 

100

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Book Value Per
Common Share

$

26.25

 

 

 

 

$

29.34

 

 

 

 

$

23.19

 

 

 

 

$

21.62

 

 

 

 

$

19.35

 

 

 

___________

1

Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investments in Kinder Morgan Energy Partners. See Note 1(B) of the accompanying Notes to Consolidated Financial Statements.

2

Reflects the acquisition of Terasen Inc. on November 30, 2005. See Note 4 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.

3

Excludes Accumulated Other Comprehensive Income/Loss.

4

As a result of our adoption of FASB Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, the subsidiary trusts associated with these securities are no longer consolidated, effective December 31, 2003.

5

Excludes the value of interest rate swaps and short-term debt. See Note 12 of the accompanying Notes to Consolidated Financial Statements.




64



KMI Form 10-K



Item 7.

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

General

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Further, unless the context requires otherwise, references to “Kinder Morgan Energy Partners” are intended to mean Kinder Morgan Energy Partners, L.P., a publicly traded pipeline master limited partnership in which we own the general partner interest and significant limited partner interests, and its consolidated subsidiaries. The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes. Specifically, as discussed in Note 1(B) of the accompanying Notes to Consolidated Financial Statements, due to our adoption of EITF No. 04-5, effective as of January 1, 2006, Kinder Morgan Energy partners and its consolidated subsidiaries are included as consolidated subsidiaries of Kinder Morgan, Inc. in our consolidated financial statements. Accordingly, their accounts, balances and results of operations are included in our consolidated financial statements for periods beginning on and after January 1, 2006, and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements pursuant to EITF 04-5, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners’ financial statements is a legal determination based on the entity that incurs the liability. The determination of responsibility for payment among entities in our consolidated group of subsidiaries was not impacted by the adoption of EITF 04-5. As discussed in Note 4 of the accompanying Notes to Consolidated Financial Statements, we acquired Terasen Inc., referred to in this report as Terasen, on November 30, 2005. In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. In prior periods, we referred to these operations as the Kinder Morgan Retail business segment. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. Refer to the heading “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding discontinued operations. In February 2007, we entered into a definitive agreement to sell our Canada-based retail natural gas operations, and as a result we recorded an estimated goodwill impairment charge of approximately $650.5 million in the fourth quarter of 2006. Our adoption of EITF No. 04-5, our acquisition of Terasen, the reclassification of the financial results of our U.S. retail natural gas distribution and related operations, the impairment of goodwill described above and other acquisitions and divestitures (including the transfer of certain assets to Kinder Morgan Energy Partners) discussed in Notes 4, 5, 6, 7 and 21 of the accompanying Notes to Consolidated Financial Statements affect comparisons of our financial position and results of operations between periods.

To convert December 31, 2006 balances denominated in Canadian dollars to U.S. dollars, we used the December 31, 2006 Bank of Canada closing exchange rate of 0.8581 U.S. dollars per Canadian dollar.

We are an energy infrastructure provider through our direct ownership and operation of energy-related assets, and through our ownership interests in and operation of Kinder Morgan Energy Partners. As described in “Business Strategy” under Items 1 and 2 “Business and Properties” elsewhere in this report, our strategy and focus continues to be on ownership of fee-based energy-related assets which are core to the energy infrastructure of North America and serve growing markets. These assets tend to have relatively stable cash flows while presenting us with opportunities to expand our facilities to serve additional customers and nearby markets. We evaluate the performance of our investment in these assets using, among other measures, segment earnings. In addition, please see “Recent Developments” under Items 1 and 2 “Business and Properties” elsewhere in this report.

The variability of our operating results is attributable to a number of factors including (i) variability within U.S. and Canadian national and local markets for energy and related services, including the effects of competition, (ii) the impact of regulatory proceedings, (iii) the effect of weather on customer energy and related services usage, as well as our operation and construction activities, (iv) increases or decreases in interest rates, (v) the degree of our success in controlling costs and identifying, carrying out profitable expansion projects and integrating new acquisitions into our operations and (vi) changes in taxation policy or regulated rates. Certain of these factors are beyond our direct control, but we operate a structured risk management program to mitigate certain of the risks associated with changes in the price of natural gas, interest rates, currency exchange rates and weather (relative to historical norms). The remaining risks are primarily mitigated through our strategic and operational planning and monitoring processes. See Item 1A “Risk Factors” elsewhere in this report.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be



65



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. The reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.

In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the effective income tax rate to apply to our pre-tax income, deferred income tax assets, deferred income tax liabilities, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for our natural gas distribution deliveries for which meters have not yet been read, cost and timing of environmental remediation efforts, the fair values used to allocate purchase price and to determine possible asset impairment charges, potential exposure to adverse outcomes from judgments, litigation settlements or transportation rate cases, exposures under contractual indemnifications, and various other recorded or disclosed amounts. Certain of these accounting estimates are of more significance in our financial statement preparation process than others.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. We do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

The recording of environmental accruals often coincides with the completion of a feasibility study or the commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations.

In 2006, we made quarterly adjustments to our environmental liabilities to reflect changes in previous estimates. In addition to quarterly reviews of potential environmental issues and resulting environmental liability adjustments, we made supplemental liability adjustments in 2006 that were primarily related to newly identified and/or recently incurred environmental issues and claims, largely related to refined petroleum products pipeline releases of Kinder Morgan Energy Partners and Plantation Pipe Line Company. These supplemental environmental liability adjustments were recorded pursuant to management’s requirement to recognize contingent environmental liabilities whenever the associated environmental issue is likely to occur and the amount of our liability can be reasonably estimated. In making these liability estimations, we considered the effect of environmental compliance, pending legal actions against us, and potential third-party liability claims.

As a result, in 2006, Kinder Morgan Energy Partners recorded a combined $35.4 million expense associated with total environmental liability adjustments, including a $17.9 million expense associated with supplemental liability adjustments. The total environmental expense adjustments (including Kinder Morgan Energy Partners’ share of environmental expense associated with liability adjustments recognized by Plantation Pipe Line Company) included a $4.1 million increase in Kinder Morgan Energy Partners’ estimated environmental receivables and reimbursables, a $3.5 million decrease in Kinder Morgan Energy Partners’ equity investments, a $34.5 million increase in Kinder Morgan Energy Partners’ overall accrued environmental and related claim liabilities, and a $1.5 million increase in Kinder Morgan Energy Partners’ accrued expense liabilities.

The $17.9 million Kinder Morgan Energy Partners expense related to supplemental environmental liability adjustments resulted in a $16.4 million increase in expense to the Products Pipelines – KMP business segment and a $1.5 million increase in expense to the Natural Gas Pipelines – KMP business segment. It consisted of a $14.9 million expense recorded within “Operations and Maintenance,” a $4.9 million expense recorded within “Equity in Earnings of Other Equity Investments,” and a $1.9 million reduction in expense recorded within “Income Taxes” in the accompanying Consolidated Statement of Operations for 2006.

Regulatory and Legal Matters

Our regulated utility operations are accounted for in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation. As a result, we record assets and liabilities that result from the ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. The accounting for these items is based on an expectation of the future decisions or approvals of the regulator. The deferral of differences between amounts included



66



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




in tolls or rates and actual experience for specified expenses is based on the expectation that the regulator will approve the refund to or recovery from customers of the deferred balance. If the regulators’ future actions are different from our expectations, the timing and amount of the recovery of assets or refund of liabilities could be substantially different from that reflected in the financial statements. When assessing whether our regulatory assets and liabilities are probable of future recovery or refund, we consider such factors as changes in the regulatory environment, recent rate orders to other regulated utilities, and the status of any pending deregulation legislation. While we believe the existing regulatory assets are probable of recovery, the current regulatory and political climate on which this assessment is based is subject to change in the future. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as better information becomes available.

SFPP, L.P. is the subsidiary limited partnership that owns Kinder Morgan Energy Partners’ Pacific operations’ pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by the Pacific operations’ pipeline systems are subject to certain proceedings at the Federal Energy Regulatory Commission (“FERC”) involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on the 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, the 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.

In December 2005, Kinder Morgan Energy Partners recorded an accrual of $105.0 million for an expense attributable to an increase in the reserves related to its rate case liability. The factors we considered when making this additional accrual included, among others: (i) the opinions and views of our legal counsel; (ii) our experience with reparations and refunds previously paid to complainants and other shippers as required by the FERC (in 2003, Kinder Morgan Energy Partners paid transportation rate reparation and refund payments in the amount of $44.9 million as mandated by the FERC); and (iii) the decision of management as to how we intended to respond to the complaints, which included the compliance filing submitted to the FERC on March 7, 2006.

In accordance with the FERC’s December 2005 Order and February 2006 Order on Rehearing, rate reductions were implemented by Kinder Morgan Energy Partners on May 1, 2006. We assume that reparations and accrued interest thereon will be paid no earlier than the second quarter of 2007; however, the timing and nature of any rate reductions and reparations that may be ordered will likely be affected by the final disposition of the application of the FERC’s new policy statement on income tax allowances to Kinder Morgan Energy Partners’ Pacific operations in FERC Docket Nos. OR92-8, OR96-2, and IS05-230 proceedings.

Kinder Morgan Energy Partners had previously estimated the combined annual impact of the rate reductions and the payment of reparations sought by shippers would be approximately 15 cents of distributable cash flow per unit. Based on our review of the December 2005 and the February 2006 Orders, and subject to the ultimate resolution of these issues in SFPP’s compliance filings and subsequent judicial appeals, we now expect the total annual impact on Kinder Morgan Energy Partners will be less than 15 cents per unit. We estimate that the actual, partial year impact on Kinder Morgan Energy Partners’ 2006 distributable cash flow was approximately $15.7 million and the partial year impact on our 2006 earnings per share was approximately $0.04 per share.

In addition, the third quarter of 2006, Kinder Morgan Energy Partners made refund payments of $19.1 million to certain shippers on the Pacific operations’ pipelines and Kinder Morgan Energy Partners reduced its rate case liability. The payment related to a settlement agreement reached in May 2006 that resolved certain challenges by complainants with regard to delivery tariffs and gathering enhancement fees at the Pacific operations’ Watson Station, located in Carson, California.

For more information regarding the Pacific operations’ regulatory proceedings, see Note 19 of the accompanying Notes to Consolidated Financial Statements.

Intangible Assets

Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets. These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to 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



67



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




of the asset has decreased below its carrying value. In accordance with the provisions of SFAS No. 142, we test our goodwill for impairment on an annual basis, and have determined that, with the exception of the goodwill associated with Terasen Gas (see Note 6 of the accompanying Notes to Consolidated Financial Statements), our goodwill is not impaired.

Our remaining intangible assets, excluding goodwill, include lease value, contracts, customer relationships, technology-based assets and agreements. These intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. As of December 31, 2006, these intangibles totaled $229.5 million.

Estimated Net Recoverable Quantities of Oil and Gas

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

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

Hedging Activities

As discussed under “Risk Management” in Item 7A of this report, we enter into derivative contracts (natural gas futures, swaps and options) solely for the purpose of mitigating risks that accompany our normal business activities, including fluctuations in foreign currency exchange, interest rates and the price of natural gas and associated transportation. We account for these derivative transactions as hedges in accordance with authoritative accounting guidelines, marking the derivatives to market at each reporting date. At December 31, 2006, the majority of our derivative financial instruments either (i) met specific hedge accounting criteria whereby the unrealized gains and losses are either recognized as part of comprehensive income or, in the case of interest rate swaps, as a valuation adjustment to the underlying debt, or (ii) related to regulated business activities where the risk is passed through to customers and accordingly the unrealized gains and losses are deferred until recovered or refunded to customers through rates. Unrealized gains or losses of derivative financial instruments that do not meet specific hedge accounting criteria or do not have the risk passed through to customers are recognized in income currently. Any inefficiency in the performance of the hedge is recognized in income currently or as appropriate, deferred in regulatory accounts and, ultimately, the financial results of the hedge are recognized concurrently with the financial results of the underlying hedged item. All but an insignificant amount of our natural gas related derivatives are for terms of 18 months or less, allowing us to utilize widely available, published forward pricing curves in determining all of our appropriate market values. Our interest rate swaps are similar in nature to many other such financial instruments and are valued for us by commercial banks with expertise in such valuations.

We engage in a hedging program to mitigate our exposure to fluctuations in currency exchange rates and 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. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. Generally, the financial statement volatility arises from an accounting requirement to recognize changes in values of financial instruments while not concurrently recognizing the values of the underlying transactions being hedged.

In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to 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. 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.



68



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Cycle Billing

In our retail natural gas distribution business (which, for our U.S.-based operations, has been reclassified to discontinued operations for all periods presented as discussed in Note 7 of the accompanying Notes to Consolidated Financial Statements), because we read customer meters on a cycle basis, we are required to estimate the amount of revenue earned as of the end of each period for which service has been rendered but meters have not yet been read. We have historical information available for these meters and, together with weather-related data that is indicative of natural gas demand, we are able to make reasonable estimates. In our natural gas pipeline businesses, we are similarly required to make estimates for services rendered but for which actual metered volumes are not available at reporting dates. As with our retail natural gas distribution business, we have historical data available to assist us in the estimation process, but the variations in volume are greater, introducing a larger possibility of error. We believe that our estimates, which are replaced with actual metered volumes in the next accounting month, provide acceptable approximations of the actual revenue earned during any period, especially given that the majority of our revenues in the pipeline business are derived from demand charges, which do not vary with the actual amount of gas transported.

Employee Benefit Plans

With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. We review historical trends, future expectations, current and projected market conditions, the general interest rate environment and benefit payment obligations to determine the assumptions. The discount rate represents the market rate for a high quality corporate bond. The selection of these assumptions is discussed in Note 13 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding (excluding the pension and retiree medical plans of Terasen and without adjustment for the change in these amounts that would be attributable to the expected disposition of our U.S.-based natural gas distribution operations), a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $642,000 ($642,000) and would increase (decrease) our annual pension expense by $2.4 million ($2.4 million) in comparison to that recorded in 2006. Similarly, and without adjustment for the expected disposition of our U.S.-based natural gas distribution operations as discussed preceding, a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $7.3 million ($6.6 million) and would increase (decrease) our projected pension benefit obligation by $28.9 million ($25.6 million) compared to those balances as of December 31, 2006.

Terasen’s postretirement benefit programs are unfunded, and therefore there is no impact to expense from a change in the long-term return assumptions. Terasen’s defined benefit pension programs are funded, but due to the significance of the regulated operations, the impact on expense of variances in long-term return assumptions and discount rates is materially recovered through rate-setting mechanisms. Terasen’s supplemental pension plans are unfunded and are therefore not subject to variances in long-term return assumptions. A 1% change in the discount rate would increase (decrease) Terasen’s accumulated postretirement benefit obligation by $12.5 million ($10.7 million) and its projected pension benefit obligation by $28.5 million ($50.9 million) compared to those balances as of December 31, 2006.

Income Taxes

We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.



69



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Consolidated Financial Results

 

Year Ended December 31,

 

20061, 2

 

20051

 

2004

 

(In millions except per share amounts)

Equity in Earnings of Kinder Morgan Energy Partners2, 3

$

-

 

 

$

605.4

 

 

$

558.1

 

Segment Earnings:4

 

 

 

 

 

 

 

 

 

 

 

NGPL5

 

499.0

 

 

 

435.2

 

 

 

392.8

 

Terasen Gas

 

312.9

 

 

 

45.2

 

 

 

-

 

Kinder Morgan Canada

 

119.9

 

 

 

12.5

 

 

 

-

 

Power

 

21.1

 

 

 

19.7

 

 

 

15.3

 

Products Pipelines – KMP

 

404.9

 

 

 

-

 

 

 

-

 

Natural Gas Pipelines – KMP

 

509.1

 

 

 

-

 

 

 

-

 

CO2 – KMP

 

295.2

 

 

 

-

 

 

 

-

 

Terminals – KMP

 

333.6

 

 

 

-

 

 

 

-

 

TransColorado

 

-

 

 

 

-

 

 

 

20.3

 

Total Segment Earnings

 

2,495.7

 

 

 

1,118.0

 

 

 

986.5

 

Impairment of Assets7, 8, 9

 

(651.7

)

 

 

(6.5

)

 

 

(33.5

)

Interest and Other Corporate Expenses, Net6, 7, 8, 9

 

(1,540.2

)

 

 

(236.1

)

 

 

(246.8

)

Income From Continuing Operations Before Income Taxes4

 

303.8

 

 

 

875.4

 

 

 

706.2

 

Income Taxes4, 10, 11

 

(255.1

)

 

 

(345.5

)

 

 

(208.0

)

Income From Continuing Operations12

 

48.7

 

 

 

529.9

 

 

 

498.2

 

Income (Loss) From Discontinued Operations, Net of Tax

 

23.2

 

 

 

24.7

 

 

 

23.9

 

Net Income

$

71.9

 

 

$

554.6

 

 

$

522.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted Earnings (Loss) Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

Income From Continuing Operations

$

0.36

 

 

$

4.25

 

 

$

3.99

 

Income (Loss) From Discontinued Operations

 

0.17

 

 

 

0.20

 

 

 

0.19

 

Total Diluted Earnings Per Common Share

$

0.53

 

 

$

4.45

 

 

$

4.18

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Shares Used in Computing Diluted Earnings Per Common Share

 

135.0

 

 

 

124.6

 

 

 

124.9

 

__________________

1

Operating results for 2006 and 2005 include the results of Terasen, which we acquired on November 30, 2005. See Note 4 of the accompanying Notes to Consolidated Financial Statements. Certain of these assets are subject to a February 2007 definitive sales agreement, see Note 21 of the accompanying Notes to Consolidated Financial Statements.

2

Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investment in Kinder Morgan Energy Partners. See Note 1(B) of the accompanying Notes to Consolidated Financial Statements.

3

Equity in Earnings of Kinder Morgan Energy Partners for 2005 includes a reduction in pre-tax earnings of approximately $63.3 million ($40.3 million after tax) resulting principally from the effects of certain regulatory, environmental, litigation and inventory items on Kinder Morgan Energy Partners’ earnings.

4

Segment earnings includes operating income before corporate costs plus earnings from equity method investments plus gains and losses on incidental sales of assets. In 2006, for our business segments that are also segments of Kinder Morgan Energy Partners, also includes interest income, other, net and an aggregate of $19.0 million of income taxes allocated to the segments.

5

Results for 2005 include a pre-tax loss of $1.7 million ($1.1 million after tax) incurred for hedge ineffectiveness.

6

Includes (i) general and administrative expenses, (ii) interest expense, (iii) minority interests and (iv) other, net.

7

Impairment of Assets in 2006 includes (i) a $650.5 million goodwill impairment associated with Terasen Gas (see Note 6 of the accompanying Notes to Consolidated Financial Statements) and (ii) a $1.2 million impairment of Power assets. Interest and Other Corporate Expenses, Net for 2006 include (i) a reduction in pre-tax income of $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps and (ii) miscellaneous other items totaling a net decrease of $0.8 million in pre-tax income ($0.5 million after tax).

8

The Impairment of Assets in 2005 was a pre-tax charge of $6.5 million ($4.1 million after tax) for the impairment of certain investments in our Power business segment. Interest and Other Corporate Expenses, Net for 2005 include (i) pre-tax gains of $73.9 million ($31.6 million after tax) from the sale of Kinder Morgan Management shares during the second



70



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




and fourth quarters of 2005, (ii) a pre-tax charge of $15.0 million ($9.5 million after tax) for our contribution to the Kinder Morgan Foundation, (iii) net pre-tax gains on currency transactions and swaps of $2.3 million ($1.4 million after tax) and (iv) a decrease in after-tax minority interest expense in Kinder Morgan Management of $19.6 million due principally to the items discussed in Note 3 above.

9

Results for 2004 include (i) a pre-tax charge of $15.0 million ($9.4 million after tax), net of the recognition of deferred power development revenues and the impact of the resolution of certain litigation contingencies, for the impairment of certain investments in our Power business segment (which impairment is presented in the Impairment of Assets line), (ii) a pre-tax charge of $3.9 million ($2.4 million after tax) due to the early extinguishment of debt and (iii) miscellaneous other items totaling a net decrease of $1.6 million in pre-tax income ($1.0 million after tax).

10

Results for 2006 include a reduction in the income tax provision of $38.0 million resulting from the adjustment of deferred tax liability amounts.

11

Results for 2004 include a reduction in the income tax provision of $65.5 million resulting from the adjustment of deferred tax liability amounts.

12

Our income from continuing operations for 2006 includes the effects of certain items of Kinder Morgan Energy Partners on our income totaling a net increase in pre-tax earnings of $3.2 million ($1.4 million after tax).

Our income from continuing operations decreased from $529.9 million in 2005 to $48.7 million in 2006. The principal reason for this decline was the impairment of certain assets as discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements. Before this impairment charge, our income from continuing operations increased from $529 million in 2005 to $699.2 million in 2006, an increase of $169.3 million (32%). The items discussed in footnotes 3, 4, 5, 7, 8 and 12 of the table above, excluding the effect of 2006 asset impairments, had the effect of increasing 2006 earnings, relative to 2005, by $27.2 million. The remaining $142.1 million increase in our 2006 income from continuing operations, before the charge for asset impairment, principally resulted from (i) our acquisition of Terasen on November 30, 2005, (ii) increased earnings from Kinder Morgan Energy Partners, net of associated minority interests, (iii) increased earnings from our NGPL and Power business segments and (iv) reduced general and administrative expenses, exclusive of the general and administrative expenses attributable to Terasen and Kinder Morgan Energy Partners. These positive impacts were partially offset by increased interest costs due, in part, to the effect of higher interest rates on our floating-rate debt. Please refer to the individual business segment discussions included elsewhere herein for additional information regarding business segment results. Refer to the headings “Interest and Corporate Expenses, Net,” “Earnings from Kinder Morgan Energy Partners,” “Income Taxes – Continuing Operations” and “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding these items.

Our income from continuing operations increased from $498.2 million in 2004 to $529.9 million in 2005, an increase of $31.7 million (6%). The items discussed in footnotes 3, 5, 8, 9 and 11 of the table above, in addition to the asset impairment recorded in 2005, had the effect of decreasing 2005 earnings, relative to 2004, by $55.1 million. The remaining $86.8 million increase in our 2005 income from continuing operations, principally resulted from (i) increased earnings from our investment in Kinder Morgan Energy Partners, exclusive of the items discussed in the table above, (ii) increased earnings from our NGPL business segment, (iii) one month of 2005 earnings attributable to our acquisition of Terasen and (iv) a $4.5 million gain on sale of Kinder Morgan Management shares in the first quarter of 2005. These favorable income impacts were partially offset by (i) the contribution of our TransColorado business segment to Kinder Morgan Energy Partners effective November 1, 2004, (ii) increased interest expense due to higher interest rates, interest expense on Terasen’s existing debt and interest expense on incremental debt issued to acquire Terasen, (iii) increased general and administrative expenses due principally to the general and administrative costs of Terasen and (iv) increased income taxes.

Diluted earnings per common share from continuing operations decreased from $4.25 in 2005 to $0.36 in 2006. The principal reason for this decline was the impairment of certain assets as discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements. Before this impairment charge, our diluted earnings per common share increased from $4.25 in 2005 to $5.18 in 2006, an increase of $0.93 (22%). This increase reflected, in addition to the financial and operating impacts discussed preceding, an increase of 10.4 million (8%) in average shares outstanding. The increase in average shares outstanding resulted from the net effects of (i) 12.5 million shares issued to acquire Terasen on November 30, 2005, (ii) decreases in shares outstanding due to our share repurchase program (see Note 10(E) of the accompanying Notes to Consolidated Financial Statements), (iii) increases in shares outstanding due to newly-issued shares for (1) the employee stock purchase plan, (2) the issuance of restricted stock and (3) exercises of stock options by employees (see Note 14 of the accompanying Notes to Consolidated Financial Statements) and (iv) the increased dilutive effect of stock options resulting from the increase in the market price of our shares. Total diluted earnings per common share increased from $4.45 in 2005 to $5.35 in 2006, an increase of $0.90 (20%).

Diluted earnings per common share from continuing operations increased from $3.99 in 2004 to $4.25 in 2005, an increase of $0.26 (7%). This increase reflected, in addition to the financial and operating impacts discussed preceding, a decrease of 0.3 million (0.2%) in average shares outstanding. The decrease in average shares outstanding resulted from the net effects of (i)



71



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




12.5 million shares issued to acquire Terasen, which were outstanding for one month during 2005, (ii) decreases in shares outstanding due to our share repurchase program (see Note 10(E) of the accompanying Notes to Consolidated Financial Statements), (iii) increases in shares outstanding due to newly-issued shares for (1) the employee stock purchase plan, (2) the issuance of restricted stock and (3) exercises of stock options by employees (see Note 14 of the accompanying Notes to Consolidated Financial Statements) and (iv) the increased dilutive effect of stock options resulting from the increase in the market price of our shares. Total diluted earnings per common share increased from $4.18 in 2004 to $4.45 in 2005, an increase of $0.27 (6%).

Results of Operations

The following comparative discussion of our results of operations is by segment for factors affecting segment earnings, and on a consolidated basis for other factors.

In August 2006, we entered into a definitive agreement with a subsidiary of General Electric Company to sell our U.S. retail natural gas distribution and related operations for $710 million plus working capital. In prior periods, we referred to these operations as the Kinder Morgan Retail business segment. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of these operations have been reclassified to discontinued operations for all periods presented. Refer to the heading “Discontinued Operations” included elsewhere in management’s discussion and analysis for additional information regarding discontinued operations.

We manage our various businesses by, among other things, allocating capital and monitoring operating performance. This management process includes dividing the company into business segments so that performance can be effectively monitored and reported for a limited number of discrete businesses.

Business Segment

Business Conducted

 

Referred to As:

  

 

 

 

Natural Gas Pipeline Company of
America and certain affiliates


The ownership and operation of a major interstate natural gas pipeline and storage system

 


Natural Gas Pipeline Company of America, or NGPL

Terasen Natural Gas Distribution

The regulated sale and transportation of natural gas to residential, commercial and industrial customers in British Columbia, Canada

 

Terasen Gas

Petroleum Pipelines

The ownership and operation of crude and refined petroleum pipelines, principally located in Canada, and a one-third interest in the Express System, a crude pipeline system

 

Kinder Morgan Canada

Power Generation

The ownership and operation of natural gas-fired electric generation facilities

 

Power

Petroleum Products Pipelines (Kinder Morgan Energy Partners)


The ownership and operation of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus associated product terminals and petroleum pipeline transmix processing facilities

 


Products Pipelines – KMP

Natural Gas Pipelines (Kinder Morgan Energy Partners)


The ownership and operation of major interstate and intrastate natural gas pipeline and storage systems

 


Natural Gas Pipelines – KMP



72



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    







CO2 (Kinder Morgan Energy Partners)

The production, transportation and marketing of carbon dioxide (CO2) to oil fields that use CO2 to increase production of oil; plus ownership interests in and/or operation of oil fields in West Texas; plus the ownership and operation of a crude oil pipeline system in West Texas

 

CO2 - KMP



Liquids and Bulk Terminals (Kinder Morgan Energy Partners)


The ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities that together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products

 


Terminals - KMP


The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1 of the accompanying Notes to Consolidated Financial Statements, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance, (ii) equity in earnings of equity method investees (other than Kinder Morgan Energy Partners, the accounts, balances and results of operations of which are now consolidated with our own) are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying Consolidated Statements of Operations), (iii) certain items included in operating income (such as general and administrative expenses) are not considered by management in its evaluation of business segment performance, (iv) gains and losses from incidental sales of assets are included in segment earnings and (v) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings in relation to the level of capital employed. In addition, because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

Following are operating results by individual business segment (before intersegment eliminations), including explanations of significant variances between the periods presented.

Natural Gas Pipeline Company of America

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions except systems throughput)

Operating Revenues

$

1,118.0

 

$

947.3

 

$

778.9

  

 

 

 

 

 

 

 

 

Gas Purchases and Other Costs of Sales

$

362.9

 

$

299.2

 

$

188.8

  

 

 

 

 

 

 

 

 

Segment Earnings

$

499.0

 

$

435.2

 

$

392.8

  

 

 

 

 

 

 

 

 

Systems Throughput (Trillion Btus)

 

1,696.3

 

 

1,664.8

 

 

1,539.6


NGPL’s segment earnings increased from $435.2 million in 2005 to $499.0 million in 2006, an increase of $63.8 million (15%). Segment revenues and earnings for 2006 were positively impacted, relative to 2005, by (i) increased transportation and storage revenues in 2006 due principally to successful re-contracting of transportation and storage services, favorable basis differentials and recent transportation and storage system expansions (as discussed below) and (ii) increased operational gas sales prices. These positive impacts were partially offset by (i) $30.2 million of expense for a stress corrosion cracking rehabilitation project (as discussed below) and pipeline integrity management programs, (ii) an increase of $4.6 million in electric compression costs and (iii) a $4.9 million increase in depreciation and amortization expense. NGPL’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. Total system throughput volumes increased by 31.5 trillion Btus in 2006, relative to 2005 due, in part,



73



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




to shippers moving significant volumes of natural gas within Texas on NGPL’s Gulf Coast Pipeline. The increase in system throughput in 2006, relative to 2005, did not have a significant direct impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from “firm” contracts in which shippers pay a “demand” fee to reserve a set amount of system capacity for their use.

NGPL’s segment earnings increased from $392.8 million in 2004 to $435.2 million in 2005, an increase of $42.4 million (11%). Segment revenues and earnings for 2005 were positively impacted, relative to 2004, by (i) increased transportation and storage service revenues in 2005 resulting, in part, from increased firm demand revenues, the recent expansion of our storage system and the acquisition of the Black Marlin Pipeline and (ii) increased operational gas sales. These positive impacts were partially offset by (i) an increase of $5.2 million in depreciation expense, (ii) an increase of $4.8 million in operations and maintenance expenses, principally attributable to higher electric compression costs, (iii) a $4.4 million increase in taxes other than income taxes, principally attributable to increased property taxes, (iv) the fact that 2004 results included $4.0 million in contractual customer penalty charges in 2004 that were billed prior to December 1, 2003, the effective date for NGPL’s Order 637 provisions, but had been reserved pending the final outcome of its Order 637 filings, (v) a $2.1 million reduction in gains from incidental sales of assets and (vi) the negative impact of significant changes in the values of various natural gas price indices relative to the value of the Henry Hub index used by the NYMEX in the valuation of derivative instruments, caused by hurricane-related supply disruptions in the Gulf of Mexico area. The increase in systems throughput in 2005, relative to 2004, was due principally to higher utilization of the Amarillo and Louisiana lines. The increase in systems throughput in 2005, relative to 2004, did not have a significant direct impact on revenues or segment earnings due to the terms of  “firm” contracts, as discussed above.

On October 10, 2006, in FERC Docket No. CP 07-3, NGPL filed seeking approval to expand its Louisiana Line by 200,000 dekatherms per day (Dth/day). This $66 million project is supported by five-year agreements that fully subscribe the additional capacity.

In a letter filed on December 8, 2005, NGPL requested that the Office of the Chief Accountant of the Federal Energy Regulatory Commission (“FERC”) confirm that NGPL’s proposed accounting treatment to capitalize the costs incurred in a one-time pipeline rehabilitation project that will address stress corrosion cracking on portions of NGPL’s pipeline system is appropriate. The rehabilitation project will be conducted over a five-year period. On June 5, 2006, in Docket No. AC 06-18, the FERC ruled on NGPL’s request to capitalize pipeline rehabilitation costs. The ruling states that NGPL must expense rather than capitalize the majority of the costs. NGPL can continue to capitalize the costs of pipe replacement and coating but costs to assess the integrity of pipe must be expensed.

During the second quarter of 2006, NGPL commenced operation of the following projects: the $21 million Amarillo cross-haul line expansion, which adds 51,000 Dth/day of capacity and is fully subscribed under long-term contracts; the $38 million Sayre storage field expansion in Oklahoma that added 10 billion cubic feet (Bcf) of capacity, which is contracted for under long-term agreements; and a $4 million, 2 Bcf expansion of no-notice delivered storage service.

In the first quarter of 2006, NGPL received certificate approval from the FERC for the $74 million expansion at its North Lansing field in east Texas that will add 10 Bcf of storage service capacity. Construction is underway and the project is expected to be in service in spring 2007.

In 2006, NGPL extended long-term firm transportation and storage contracts with some of its largest shippers, including Northern Illinois Gas Company (Nicor), The Peoples Gas Light and Coke Company, Centerpoint Energy Minnesota Gas, Interstate Power and Light Company, subsidiaries of Ameren Corporation, and Wisconsin Electric Power Co. Combined, the contracts represent approximately 0.49 million Dth per day of annual firm transportation service.

Substantially all of NGPL’s pipeline capacity is committed under firm transportation contracts ranging from one to five years. Under these contracts, over 90% of the revenues are derived from a demand charge and, therefore, are collected regardless of the volume of gas actually transported. The principal impact of the actual level of gas transported is on fuel recoveries, which are received in-kind as volumes move on the system. Approximately 63% of the total transportation volumes committed under NGPL’s long-term firm transportation contracts in effect on February 13, 2007 had remaining terms of less than three years. Contracts representing approximately 6.3% of NGPL’s total long-haul, contracted firm transport capacity as of January 31, 2007 are scheduled to expire during 2007. NGPL continues to actively pursue the renegotiation, extension and/or replacement of expiring contracts.

Our principal exposure to market variability is related to the variation in natural gas prices and basis differentials, which can affect gross margins in our NGPL segment. “Basis differential” is a term that refers to the difference in natural gas prices between two locations or two points in time. These price differences can be affected by, among other things, natural gas supply and demand, available transportation capacity, storage inventories and deliverability, prices of alternative fuels and weather conditions. In recent periods, additional competitive pressures have been generated in Midwest natural gas markets due to the introduction and planned introduction of pipeline capacity to bring additional supplies of natural gas into the



74



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Chicago market area, although incremental pipeline capacity to take gas out of the area has also been constructed. We have attempted to reduce our exposure to this form of market variability by pursuing long-term, fixed-rate type contract agreements to utilize the capacity on NGPL’s system. In addition, as discussed under “Risk Management” in Item 7A of this report and in Note 12 of the accompanying Notes to Consolidated Financial Statements, we utilize a comprehensive risk management program to mitigate our exposure to changes in the market price of natural gas and associated transportation.

The majority of NGPL’s system is subject to rate regulation under the jurisdiction of the Federal Energy Regulatory Commission. Currently, there are no material proceedings challenging the rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for) on any of our pipeline systems. Nonetheless, shippers on our pipelines do have rights, under certain circumstances prescribed by applicable regulations, to challenge the rates we charge. There can be no assurance that we will not face future challenges to the rates we receive for services on our pipeline systems.

Terasen Gas

 

Year Ended December 31,

 

Month Ended December 31,

 

2006

 

2005

 

(In millions)

Operating Revenues

$

1,523.9

 

$

223.3

  

 

 

 

 

 

Gas Purchases and Other Costs of Sales

$

978.6

 

$

156.2

  

 

 

 

 

 

Segment Earnings1

$

312.9

 

$

45.2


1 Does not include $650.5 pre-tax goodwill impairment in 2006.

The results of operations of Terasen Gas are included in our results beginning with the November 30, 2005 acquisition of Terasen. Terasen’s natural gas distribution operations consist primarily of Terasen Gas Inc., Terasen Gas (Vancouver Island) Inc. (“TGVI”) and Terasen Gas (Whistler) Inc., collectively referred to in this report as Terasen Gas. Terasen Gas is regulated by the British Columbia Utilities Commission (“BCUC”).

On February 26, 2007, we entered into a definitive agreement to sell Terasen Inc. to Fortis Inc. (TSX: FTS), a Canadian-based company with investments in regulated distribution utilities, for approximately $3.2 billion (C$3.7 billion) including cash and assumed debt. Terasen Inc.’s principal assets include Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. The transaction is subject to certain closing conditions and regulatory approvals and is expected to close in mid 2007.  This sale does not include assets of Kinder Morgan Canada.

In June 2006, the BCUC approved an application from Terasen Gas Inc. to build a 50-kilometer natural gas pipeline from Squamish to Whistler. The estimated C$42 million project, which includes the cost of retrofitting utility customers’ gas-fired appliances from propane to natural gas use, will replace an aging propane system. Construction on this project is being integrated with and performed by the contractor performing the highway upgrades to Whistler in advance of the 2010 Winter Olympics. We expect full service to be available to Whistler by November 2008.

Terasen Gas Inc.’s allowed return on equity (“ROE”) is determined annually based on a formula that applies a risk premium to a forecast of long-term Government of Canada bond yields. For 2005, the application of the ROE formula set Terasen Gas Inc.’s allowed ROE at 9.03%, down from 9.15% in 2004. On March 2, 2006, a decision was issued by the BCUC, with an effective date of January 1, 2006, approving changes to Terasen Gas Inc.’s and TGVI’s deemed equity components from 33% to 35% and from 35% to 40%, respectively. The same decision also modified the previously existing generic ROE reset formula resulting in an increase in allowed ROEs from the levels that would have resulted from the old formula. The changes increased the allowed ROE from 8.29% to 8.80% for Terasen Gas Inc. and from 8.79% to 9.50% for TGVI in 2006 and the new formula resulted in allowed ROEs for 2007 of 8.37% and 9.07% for Terasen Gas Inc. and TGVI, respectively.

Kinder Morgan Canada (Formerly Terasen Pipelines)

 

Year Ended December 31,

 

Month Ended December 31,

 

2006

 

2005

 

(In millions)

Operating Revenues

$

213.7

 

$

18.9

  

 

 

 

 

 

Segment Earnings

$

119.9

 

$

12.5




75



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




The results of operations of Kinder Morgan Canada (formerly Terasen Pipelines) are included in our results beginning with the November 30, 2005 acquisition of Terasen. Kinder Morgan Canada’s operations consist primarily of the Trans Mountain pipeline, the Corridor pipeline and a one-third interest in the Express System.

In November 2004, Trans Mountain entered into negotiations with the Canadian Association of Petroleum Producers (“CAPP”) and principal shippers for a new Incentive Toll Settlement to be effective for the period starting January 1, 2006 and ending December 31, 2010 (the “2006 ITS”). In January 2006, Trans Mountain reached agreement in principle reduced to a memorandum of understanding for the 2006 ITS. A final agreement was reached with CAPP in October 2006 and NEB approval was received in November 2006. The 2006 ITS provides the commercial support for the much needed first phase of expansion of the Trans Mountain pipeline system, which will increase capacity to 300,000 barrels per day (“bpd”). The project includes the Trans Mountain pump station expansion that will increase pipeline capacity from the current 225,000 bpd to 260,000 bpd by April 2007, and the Anchor Loop expansion, which will add an additional 40,000 bpd of new capacity to the west coast of British Columbia and Washington state by late 2008. These projects represent approximately C$638 million in capital investments and reflect a commitment by Kinder Morgan Canada to progressively expand pipeline capacity from Alberta to serve markets in Canada, the United States and offshore.

Kinder Morgan Canada filed a comprehensive environmental report with the Canadian Environmental Assessment Agency on November 15, 2005, and filed a complete NEB application for the Anchor Loop Project on February 17, 2006. The C$443 million project involves looping a 98-mile section of the existing Trans Mountain pipeline system between Hinton, Alberta, and Jackman, British Columbia, and the addition of three new pump stations. With construction of the Anchor Loop, the Trans Mountain system’s capacity will increase from 260,000 bpd to 300,000 bpd by the end of 2008. The public hearing of the application was held the week of August 8, 2006. On October 26, 2006, the NEB released its favorable decision on the application.

On November 10, 2005, Kinder Morgan Canada received approval from the NEB to increase the capacity of the Trans Mountain pipeline system from 225,000 bpd to 260,000 bpd. The C$195 million expansion is designed to add 35,000 bpd of heavy crude oil capacity by building new and upgrading existing pump stations along the pipeline system between Edmonton, Alberta, and Burnaby, British Columbia. Construction began in the summer of 2006 and the expansion is expected to be in service by April 2007.

On May 2, 2006, Kinder Morgan Canada announced the start of a binding open season for the second major stage of its West Coast expansion of the Trans Mountain pipeline system. Known as TMX-2, this proposed project would add 100,000 bpd of incremental capacity to the Trans Mountain pipeline system, bringing the pipeline’s total capacity to approximately 400,000 bpd. The TMX-2 open season began on May 2, 2006, and closed on July 17, 2006 without full subscription for the expanded pipeline. Discussions with shippers are ongoing and we remain confident that shippers will ultimately support the expansion. TMX-2 is part of a multi-staged expansion designed to link growing western Canadian oil production with West Coast and offshore markets. The project consists of two pipeline loops: (i) 252 kilometers of 36-inch diameter pipe in Alberta between Edmonton and Edson, and (ii) 243 kilometers of 30- and 36-inch diameter pipe in British Columbia between Rearguard and Darfield, north of Kamloops. The proposed loops will generally follow the existing 24-inch diameter Trans Mountain pipeline. New pump stations and storage tank facilities will also be required for the TMX-2 project.

We have initiated engineering, environmental, consultation and procurement activities on the proposed Corridor pipeline expansion project, as authorized and supported by shipper resolutions and the underlying firm service agreement. The proposed C$1.8 billion expansion includes building a new 42-inch diameter diluent/bitumen (“dilbit”) pipeline, a new 20-inch diameter products pipeline, tankage and upgrading existing pump stations along the existing pipeline system from the Muskeg River Mine north of Fort McMurray to the Edmonton region. The Corridor pipeline expansion would add an initial 180,000 bpd of dilbit capacity to accommodate the new bitumen production from the Muskeg River Mine. An expansion of the Corridor pipeline system has been completed in 2006 increasing the dilbit capacity to 278,000 bpd by upgrading existing pump station facilities. By 2009, the dilbit capacity of the Corridor system is expected to be approximately 460,000 bpd. An application for the Corridor pipeline expansion project was filed with the Alberta Energy Utilities Board and Alberta Environment on December 22, 2005, and approval was received in August 2006. Construction of the Corridor pipeline expansion began in November 2006 as the shippers have received definitive approval of their Muskeg River Mine expansion.



76



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Power

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions)

Operating Revenues

$

60.0

 

$

54.2

 

$

70.0

  

 

 

 

 

 

 

 

 

Gas Purchases and Other Costs of Sales

$

8.4

 

$

3.5

 

$

4.7

  

 

 

 

 

 

 

 

 

Segment Earnings1

$

21.1

 

$

19.7

 

$

15.3

________

1

Does not include (i) pre-tax charges of $6.5 million and $33.5 million in 2005 and 2004, respectively, to record the impairment of certain assets, (ii) incremental earnings of $18.5 million in 2004 reflecting (1) the recognition of previously deferred revenues associated with construction of the Jackson, Michigan power generation facility, (2) gains from the sale of surplus power generation equipment and (3) the settlement of certain litigation. These items are discussed below.

Power’s segment earnings, as reported above, increased from $19.7 million in 2005 to $21.1 million in 2006, an increase of $1.4 million (7%). Segment results were positively impacted in 2006, relative to 2005, by (i) the recognition of $2.7 million of gains from surplus equipment sales (see Note 5 of the accompanying Notes to Consolidated Financial Statements) and (ii) a reduction in amortization expense resulting from prior period asset write-downs. These positive impacts were offset by (i) a pre-tax charge of $1.2 million to reduce the carrying value of certain surplus equipment held for sale and (ii) a $0.3 million reduction in earnings from Thermo Cogeneration Partnership due, in part, to (i) the fact that 2005 results included proceeds from the resolution of the Enron bankruptcy proceeding and (ii) increased operating expenses.

Power’s segment earnings, as reported above, increased from $15.3 million in 2004 to $19.7 million in 2005, an increase of $4.4 million (29%). Segment earnings for 2005 were positively impacted, relative to 2004, principally by a $3.0 million increase in equity earnings from Thermo Cogeneration Partnership due largely to (i) the favorable resolution of claims in the Enron bankruptcy proceeding, (ii) higher capacity revenues and (iii) reduced 2005 interest expense resulting from the repayment of long-term debt. In addition, Power was positively impacted by earnings from providing operating and maintenance management services, starting in June 2005, at a new 103-megawatt combined-cycle natural gas-fired power plant in Snyder, Texas, which is generating electricity for Kinder Morgan Energy Partners’ SACROC operations. Certain surplus power generation equipment was sold during 2004 (see Note 5 of the accompanying Notes to Consolidated Financial Statements). We recorded $3.9 million of pre-tax gains from these sales in 2004, which are excluded from segment earnings as reported above. In addition, we recorded revenues of $13.3 million and $1.3 million in 2004 resulting from development fees associated with the Jackson, Michigan power plant and the favorable settlement of litigation matters, respectively, which are excluded from the tabular presentation of segment earnings as reported above.

In February 2001, Kinder Morgan Power announced an agreement under which Williams Energy Marketing and Trading agreed to supply natural gas to and market capacity for 16 years for a 550-megawatt natural gas-fired Orion technology electric power plant in Jackson, Michigan. Effective July 1, 2002, construction of this facility was completed and commercial operations commenced. Concurrently with commencement of commercial operations, (i) Kinder Morgan Power made a preferred investment in Triton Power Company LLC (now valued at approximately $119 million); and (ii) Triton Power Company LLC, through its wholly owned subsidiary, Triton Power Michigan LLC, entered into a 40-year lease of the Jackson power facility from the plant owner, AlphaGen Power, LLC. Williams Energy Marketing and Trading supplies all natural gas to and purchases all power from the power plant under a 16-year tolling agreement with Triton Power Michigan LLC. Our preferred equity interest has no management or voting rights, but does retain certain protective rights, and is entitled to a cumulative return, compounded monthly, of 9.0% per annum. No income was recorded in 2006 and no income is expected in 2007 from this preferred investment due to the fact that the dividend on this preferred is not currently being paid, and uncertainty concerning the date at which such distributions will be received.

In May 2000, Kinder Morgan Power and Mirant Corporation (formerly Southern Energy Inc.) announced plans to build a 550 megawatt natural gas-fired electric power plant in Wrightsville, Arkansas, utilizing Kinder Morgan Power’s Orion technology. Construction of this facility was completed on July 1, 2002 and commercial operations commenced. During the third quarter of 2003, we announced that Mirant had placed the Wrightsville, Arkansas plant in bankruptcy, and we would assess the long-term prospects for this facility during the fourth quarter. In December 2003, we completed our analysis and determined that it was no longer appropriate to assign any carrying value to our investment in this facility and recorded a $44.5 million pre-tax charge, effectively writing off our remaining investment in the Wrightsville power facility. During the third quarter of 2005, and subsequent to a negotiated settlement agreement approved by the court, Mirant sold the Wrightsville power facility to Arkansas Electric Cooperative Corporation.



77



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




During 2002, we noted that a number of factors had negatively affected Power’s business environment and certain of its current operations. These factors, which are currently expected to continue in the near to intermediate term, include (i) volatile and generally declining prices for wholesale electric power in certain markets, (ii) cancellation and/or postponement of the construction of a number of new power generation facilities, (iii) difficulty in obtaining air permits with acceptable operating conditions and constraints and (iv) a marked deterioration in the financial condition of a number of participants in the power generating and marketing business, including participants in the power plants in Jackson, Michigan and Wrightsville, Arkansas. During the fourth quarter of 2002, after completing an analysis of these and other factors to determine their impact on the market value of these assets and the prospects for this business in the future, we (i) determined that we would no longer pursue power development activities and (ii) recorded a $134.5 million pre-tax charge to reduce the carrying value of our investments in (1) sites for future power plant development, (2) power plants and (3) turbines and associated equipment.

Since 1998, we have had an investment in a 76 megawatt gas-fired power generation facility located in Greeley, Colorado. We became concerned with the value of this investment as a result of several recent circumstances including the expiration of a gas purchase contract, the amendment of the associated power purchase agreement and uncertainties surrounding the management of this facility, which has changed ownership twice in the last one and one-half years. These ownership changes made it difficult for us to obtain information necessary to forecast the future of this asset. During the fourth quarter of 2004, we concluded that we had sufficient information to determine that our investment had been impaired and, accordingly, reduced our carrying value by $26.1 million. During the fourth quarter of 2005, we concluded that we had sufficient information to determine that our investment had been further impaired and, accordingly, reduced our carrying value by an additional $6.5 million. These charges are excluded from the tabular presentation of segment earnings as reported above.

During 2004, we sold five of our surplus turbines and certain associated equipment, including certain equipment to Kinder Morgan Energy Partners (see Note 5 of the accompanying Notes to Consolidated Financial Statements). Recognizing the effects of changes in technology and the limited improvement of the general economies of the electric generation industry, we determined that the carrying values of our remaining turbines and associated equipment should be reduced. In the fourth quarter of 2004, we reduced the carrying value of these assets by $7.4 million. This charge is excluded from segment earnings as reported above. In addition, in the fourth quarter of 2006, we reduced the carrying value of our remaining surplus equipment held for sale by $1.2 million. We are continuing our efforts to sell the remaining inventory of surplus equipment, which had a carrying value of $4.3 million at December 31, 2006.

Pursuant to a right we obtained in conjunction with the 1998 acquisition of the Thermo Companies, in December 2003, we made an additional investment in our Colorado power businesses in the form of approximately 1.8 million Kinder Morgan Management shares that we owned. We delivered these shares to an entity controlled by the former Thermo owners, which entity is required to retain the shares until they vest (400,000 shares vested each January 1 of 2004, 2005 and 2006, and the remainder vested on January 1, 2007). We recorded our increased investment based on the third-party-determined $56.1 million fair value of the shares as of the contribution date, with a corresponding liability representing our obligation to deliver vested shares in the future. The effect of this incremental investment will be to increase our ownership interest in the Thermo entities beginning in 2010.

We have entered into a purchase and sale agreement with a third party to sell our interests in the Power segment’s three natural gas-fired electricity generation facilities located in Colorado. The sale is subject to a right of first refusal and regulatory approvals. There can be no assurance that the conditions to the completion of this transaction will be satisfied.

Products Pipelines – KMP

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions, except operating statistics)

Revenues

$

776.3

 

 

$

711.9

 

 

$

645.2

 

Operating Expenses(Including Adjustments)a

 

(308.3

)

 

 

(366.0

)

 

 

(222.0

)

Earnings from Equity Investmentsb

 

16.3

 

 

 

28.4

 

 

 

29.0

 

Interest Income and Other, Net– Income (Expense)c

 

12.0

 

 

 

6.1

 

 

 

4.7

 

Income Taxesd

 

(5.1

)

 

 

(10.3

)

 

 

(12.0

)

Earnings Before Depreciation, Depletion and
Amortization Expense and Amortization of Excess
Cost of Equity Investments

 

491.2

 

 

 

370.1

 

 

 

444.9

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, Depletion and Amortization Expense

 

(82.9

)

 

 

(79.2

)

 

 

(71.3

)

Amortization of Excess Cost of Equity Investments

 

(3.4

)

 

 

(3.4

)

 

 

(3.3

)

Segment Earnings

$

404.9

 

 

$

287.5

 

 

$

370.3

 



78



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    








 

Year Ended December 31,

 

2006

 

2005

 

2004

Gasoline (MMBbl)

 

455.2

 

 

 

457.8

 

 

 

459.1

 

Diesel Fuel (MMBbl)

 

161.0

 

 

 

166.0

 

 

 

161.7

 

Jet Fuel (MMBbl)

 

119.5

 

 

 

118.1

 

 

 

117.8

 

Total Refined Products Volumes (MMBbl)

 

735.7

 

 

 

741.9

 

 

 

738.6

 

Natural Gas Liquids (MMBbl)

 

38.8

 

 

 

37.3

 

 

 

43.9

 

Total Delivery Volumes (MMBbl)e

 

774.5

 

 

 

779.2

 

 

 

782.5

 

_____________


a

2006 amount includes expense of $13.5 million associated with supplemental environmental liability adjustments. 2005 amount includes expense of $19.6 million associated with environmental liability adjustments, expense of $105.0 million associated with a rate case liability adjustment, and expense of $13.7 million associated with a North System liquids inventory reconciliation adjustment. 2004 amount includes expense of $30.6 million associated with environmental liability adjustments.

b

2006 amount includes expense of $4.9 million associated with environmental liability adjustments on Plantation Pipe Line Company.

c

2006 amount includes income of $5.7 million from the settlement of transmix processing contracts.  

d

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

e

Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cypress and Heartland pipeline volumes.

Due to the adoption of EITF 04-5 (see Note 1(B) of the accompanying Notes to Consolidated Financial Statements), effective January 1, 2006, we include the results of operations of Kinder Morgan Energy Partners in our consolidated results of operations. Although we accounted for Kinder Morgan Energy Partners under the equity method during 2005 and 2004, for comparative purposes, the following discussion regarding the segment results of the Products Pipelines – KMP business segment includes segment results for 2006, 2005 and 2004.

The Products Pipelines - KMP segment’s primary businesses include transporting refined petroleum products and natural gas liquids through pipelines and operating liquid petroleum products terminals and petroleum pipeline transmix processing facilities. The segment reported earnings before depreciation, depletion and amortization of $491.2 million on revenues of $776.3 million in 2006. This compares with earnings before depreciation, depletion and amortization of $370.1 million on revenues of $711.9 million in 2005, and earnings before depreciation, depletion and amortization of $444.9 million on revenues of $645.2 million in 2004.

Segment Earnings before Depreciation, Depletion and Amortization

The segment’s overall $121.1 million (33%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $74.8 million (17%) decrease in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004  included an increase of $127.5 million and a decrease of $107.6 million, respectively, from the combined net effect of the certain other items described in the footnotes to the table above. These items consisted of the following:

·

an increase in earnings of $5.7 million in 2006—related to two separate contract settlements from the petroleum transmix processing operations. First, we recorded income of $6.2 million from fees received for the early termination of a long-term transmix processing agreement at the Colton, California processing facility. Secondly, we recorded an expense of $0.5 million related to payments made to Motiva Enterprises LLC in June 2006 to settle claims for prior period transmix purchase costs at the Richmond, Virginia processing facility. We included the net income of $5.7 million from these two items within “Other, Net” in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006;

·

a decrease in earnings of $105.0 million in 2005—due to an increase in operating expenses related to an adjustment to the products pipelines rate case liability in December 2005. This adjustment is more fully described above in “Critical Accounting Policies and Estimates—Regulatory and Legal Matters;”

·

decreases in earnings of $16.4 million, $19.6 million and $30.6 million, respectively in 2006, 2005 and 2004—due to the increases in expenses associated with the adjustments of our environmental liabilities; and



79



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




·

a decrease in earnings of $13.6 million in 2005—due to an increase in operating expenses related to adjustments made to account for differences between physical and book natural gas liquids inventory on our North System natural gas liquids pipeline. This inventory expense was based on a reconciliation of the North System’s natural gas liquids inventory that was completed in the fourth quarter of 2005.

The remaining $6.4 million (1%) decrease in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, and the remaining $32.8 million (7%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 consisted of the following items:

·

a decrease in earnings of $24.2 million in 2006—due to incremental pipeline maintenance expenses recognized in the last half of 2006. Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within the Products Pipelines – KMP segment (including Plantation Pipe Line Company, Kinder Morgan Energy Partners’ 51%-owned equity investee) began recognizing certain costs incurred as part of its pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. The overall decrease in earnings consisted of an $11.6 million decrease related to a change that transferred certain pipeline integrity management costs from sustaining capital expenditures (within “Property, Plant and Equipment, Net” on our accompanying Consolidated Balance Sheets) to maintenance expense (within “Operations and Maintenance” in our accompanying Consolidated Statements of Operations) and a $12.6 million decrease related to the expensing of pipeline integrity costs in the second half of 2006.

Pipeline integrity costs encompass those costs incurred as part of an overall pipeline integrity management program, which is a process for assessing and mitigating pipeline risks in order to reduce both the likelihood and consequences of incidents. An effective pipeline integrity program is a systematic, comprehensive process that entails pipeline assessment services, maintenance and repair services, and regulatory compliance. Our pipeline integrity program is designed to provide our management the information needed to effectively allocate resources for appropriate prevention, detection and mitigation activities. Combined, this change reduced the segment’s earnings before depreciation, depletion and amortization expenses by $24.2 million in 2006—increasing maintenance expenses by $20.1 million, decreasing earnings from equity investments by $6.6 million, and decreasing income tax expenses by $2.5 million;

·

increases of $4.9 million (15%) and $18.6 million (133%), respectively, from the Southeast refined products terminal operations. The Southeast terminal operations consist of 24 refined products terminals located in the southeastern United States that Kinder Morgan Energy Partners acquired since December 2003. The increase in earnings before depreciation, depletion and amortization in 2006 compared to 2005 was driven by higher liquids throughput volumes at higher rates, relative to 2005, and higher margins from ethanol blending and sales activities.

The 2005 increase included incremental earnings of $12.2 million from both the seven refined products terminal operations Kinder Morgan Energy Partners acquired in March 2004 from Exxon Mobil Corporation and the nine refined products terminal operations Kinder Morgan Energy Partners acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC. This incremental amount represents the acquired terminals’ earnings during the additional months of ownership in 2005, as compared to 2004, and does not include increases or decreases during the same months Kinder Morgan Energy Partners owned the assets in both years. The remaining $6.4 million (46%) increase in earnings in 2005 versus 2004 (representing the increase from the same months Kinder Morgan Energy Partners owned all assets in both years) was primarily due to higher product throughput revenues;

·

increases of $4.1 million (1%) and $20.8 million (7%), respectively, from the combined Pacific and CALNEV Pipeline operations. The increase in earnings in 2006 compared to 2005 was primarily due to a $22.6 million (6%) increase in operating revenues, which more than offset an $18.3 million (18%) increase in combined operating expenses. The increase in operating revenues consisted of a $14.7 million (5%) increase from refined products deliveries and a $7.9 million (8%) increase from terminal and other fee revenue. The increase in operating expenses included incremental environmental expenses of $7.3 million and incremental fuel and power expenses of $8.3 million. These incremental environmental expenses were associated with the quarterly true-ups of estimated environmental liability adjustments and were not included with the expenses associated with the supplemental environmental liability adjustments discussed above in “Critical Accounting Policies and Estimates—Environmental Matters.” The increase in fuel and power expenses in 2006 compared to 2005 was largely the result of higher electricity usage and higher utility rates in 2006.

The increase in earnings in 2005 compared to 2004 was primarily revenue driven—revenues from refined petroleum products deliveries increased $24.1 million (9%) and terminal service revenues increased $7.5 million (8%). The increase reflects higher pipeline delivery revenues from the Pacific operations’ North Line pipeline, largely due to



80



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




the completion of a $95 million capital expansion project in December 2004. The expansion project increased the capacity of the North Line by approximately 40%, and involved the replacement of an existing 70-mile, 14-inch diameter pipeline segment with a new 20-inch diameter line and the rerouting of certain pipeline segments away from environmentally sensitive areas and residential neighborhoods;

·

increases of $3.7 million (12%) and $1.2 million (4%), respectively, from the Central Florida Pipeline. Both increases were mainly due to higher year-over-year product delivery revenues—the 2006 revenue increase was driven by higher average tariff and terminal rates, and the 2005 revenue increase resulted from an 8% increase in throughput delivery volumes;

·

an increase of $3.1 million (11%) and a decrease of $1.7 million (6%) respectively, from the combined operations of the North System and Cypress natural gas liquids pipelines. The increase in earnings in 2006 compared to 2005 consisted of a $3.3 million (15%) increase from the North System and a $0.2 million (4%) decrease from the Cypress Pipeline. The increase from the North System was primarily due to a $2.5 million (6%) increase in system throughput revenues, and the decrease from Cypress was mainly due to higher fuel and power costs, related to an over 2% increase in natural gas liquids delivery volumes in 2006 versus 2005.

The decrease in earnings in 2005 compared to 2004 consisted of a $0.8 million (4%) decrease from the North System and a $0.9 million (15%) decrease from the Cypress Pipeline. The North System decrease was mainly due to higher product storage expenses, related to both a new storage contract agreement entered into in April 2004 and higher levels of year-end inventory in 2005. The Cypress Pipeline decrease was driven by lower revenues, the result of a 17% decrease in throughput volumes that was largely due to the third quarter 2005 hurricane-related closure of a petrochemical plant in Lake Charles, Louisiana that is served by the pipeline.

·

an increase of $2.6 million (13%) and a decrease of $2.0 million (9%), respectively, from the petroleum pipeline transmix processing operations. The 2006 increase consisted of incremental earnings of $3.0 million from the inclusion of the Greensboro, North Carolina transmix facility in 2006, and a decrease in earnings of $0.4 million from the combined operations of the remaining transmix facilities, largely due to higher operating, fuel and power costs which offset increases in processing revenues. In the second quarter of 2006, Kinder Morgan Energy Partners completed construction and placed into service the approximate $11 million Greensboro facility, which is capable of processing 6,000 barrels of transmix per day for Plantation and other interested parties. In 2006, the facility earned revenues of $3.6 million and incurred operating expenses of $0.6 million.

The $2.0 million decrease in earnings in 2005 relative to 2004 was due to both lower revenues and lower other income. The decrease in revenues was due to a nearly 6% decrease in processing volumes, largely resulting from the disallowance, beginning in July 2004, of methyl tertiary-butyl ether blended transmix in the State of Illinois. The decrease in other income was due to a $0.9 million benefit taken from the reversal of certain short-term liabilities in the second quarter of 2004;

·

an increase of $1.6 million (8%) and a decrease of $3.4 million (15%), respectively, from Kinder Morgan Energy Partners’ 49.8% ownership interest in the Cochin pipeline system. The 2006 increase was largely related to lower pipeline operating expenses in 2006 compared to 2005. The decrease in expenses, including labor and power costs, resulted from year-to-year decreases in both pipeline delivery volumes and pipeline repair costs. The decrease in expenses more than offset a 1% drop in operating revenues in 2006 versus 2005, due mainly to a decrease in transportation volumes resulting from pipeline operating pressure restrictions.

The decrease in earnings in 2005 resulted from both lower transportation revenues and higher operating expenses, when compared to 2004. The decrease in revenues was due to a drop in delivery volumes caused by extended pipeline testing and repair activities and by warmer winter weather, and the increase in operating expenses was due principally to higher pipeline repair, maintenance and testing costs;

·

decreases of $2.0 million (5%) and $2.6 million (6%), respectively, from the West Coast terminal operations. The 2006 decrease reflects incremental environmental expenses of $6.2 million recognized in 2006 and not included with the expenses associated with the supplemental environmental liability adjustments discussed above. These environmental expenses followed quarterly reviews of any potential environmental issues that could impact the West Coast terminal operations and, when aggregated with all remaining expenses, resulted in a combined $9.0 million (46%) increase in operating expenses in 2006 versus 2005. The higher expenses more than offset a $6.5 million (11%) increase in operating revenues, largely attributable to higher fees from ethanol blending services and from revenue increases across all service activities performed at the Carson, California and connected Los Angeles Harbor products terminal.



81



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




The decrease in earnings in 2005 compared to 2004 was largely due to higher property tax expenses in 2005, due to expense reversals taken in the second quarter of 2004 pursuant to favorable property reassessments, and to lower product revenues resulting from the fourth quarter 2004 closure of the Gaffey Street products terminal located in San Pedro, California; and

·

a decrease of $0.2 million (0%) and an increase of $1.9 million (6%), respectively, from Kinder Morgan Energy Partners’ approximate 51% ownership interest in Plantation Pipe Line Company. Earnings before depreciation, depletion and amortization from the investment in Plantation were essentially flat in 2006 versus 2005, as lower equity earnings were mostly offset by lower operatorship expenses. The decrease in both lower net income and pipeline operating expenses were associated with lower year-to-year transportation revenues, due primarily to an almost 7% drop in overall refined products delivery volumes in 2006. The decline in volumes was primarily due to alternative pipeline service into Southeast markets and to changes in supply from Louisiana and Mississippi refineries related to new ultra low sulfur diesel and ethanol blended gasoline requirements. The drop in revenues was largely offset by lower operating and power expenses, due to the lower transportation volumes.

The increase in earnings in 2005 relative to 2004 was mainly due to the recognition, in 2005, of incremental interest income of $2.5 million on Kinder Morgan Energy Partners’ long-term note receivable from Plantation. In July 2004, Kinder Morgan Energy Partners loaned $97.2 million to Plantation to allow it to pay all of its outstanding credit facility and commercial paper borrowings and in exchange for this funding, Kinder Morgan Energy Partners received a seven year note receivable bearing interest at the rate of 4.72% per annum.

Segment Details

Revenues for the segment increased $64.4 million (9%) in 2006 compared to 2005, and increased $66.7 million (10%) in 2005 compared to 2004. The respective year-to-year increases in segment revenues were principally due to the following:

·

increases of $24.5 million (43%) and $33.1 million (141%), respectively, from the Southeast terminals. The 2006 increase was largely attributable to higher ethanol blending and sales revenues and higher liquids inventory sales (offset by higher costs of sales, as described below). The 2005 increase was primarily due to terminal acquisitions—including incremental revenues of $23.5 million attributable to the Charter terminals Kinder Morgan Energy Partners acquired in November 2004, and $2.6 million attributable to the ExxonMobil terminals Kinder Morgan Energy Partners acquired in March 2004;

·

increases of $16.2 million (5%) and $26.6 million (8%), respectively, from the Pacific operations. The increase in revenues in 2006 compared to 2005 consisted of a $9.8 million (4%) increase in refined products delivery revenues and a $6.4 million (7%) increase in refined products terminal revenues in 2006, compared to 2005. The increase from product deliveries reflect a 2% increase in mainline delivery volumes in 2006, and includes the impact of both rate reductions that went into effect on May 1, 2006, based on FERC filings associated with the Pacific operations’ rate litigation, and rate increases that went into effect July 1, 2006 and July 1, 2005, according to the FERC annual index rate increase (a producer price index-finished goods adjustment). The increase from terminal revenues was due to the higher transportation barrels and to incremental service revenues, including diesel lubricity-improving injection services that Kinder Morgan Energy Partners began offering in May 2005.

·

The Pacific operations’ $26.6 million increase in revenues in 2005 relative to 2004 included increases of $21.2 million (9%) from mainline refined products delivery revenues and $5.4 million (6%) from incremental terminal revenues. The increase from products delivery revenues was driven by a 2% increase in mainline delivery volumes and by increases in average mainline tariff rates; the increase from terminal operations was primarily due to increased terminal and ethanol blending services, largely as a result of the increase in pipeline throughput, and to incremental revenues from diesel lubricity-improving injection services.

·

The increase in mainline tariff rates included both FERC approved annual indexed interstate tariff increases in July 2004 and 2005, and a filed rate increase on the completed North Line expansion with the California Public Utility Commission. In November 2004, Kinder Morgan Energy Partners filed an application with the CPUC requesting a $9 million increase in existing California intrastate transportation rates to reflect the in-service date of the $95 million North Line expansion project. Pursuant to CPUC regulations, this increase automatically became effective December 22, 2004, but is being collected subject to refund, pending resolution of protests to the application by certain shippers;

·

an increase of $6.5 million (11%) in 2006 versus 2005 from the West Coast terminals. Terminal revenues were flat across both 2005 and 2004, but increased in 2006 compared to 2005 due to storage rent escalations, higher throughput barrels and rates at various locations, and additional tank capacity at the Carson/Los Angeles Harbor system terminals;



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Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




·

increases of $6.4 million (11%) and $5.0 million (9%), respectively, from the CALNEV Pipeline. The increase in 2006 compared to 2005 consisted of a $4.9 million (11%) increase from higher refined products deliveries and a $1.5 million (11%) increase from overall terminal revenues. The increase from products deliveries was due to a 4% increase in delivery volumes and a 6% increase in average tariff rates (including FERC annual index rate increases in July 2006 and 2005). The higher terminal revenues resulted primarily from additional transportation barrel deliveries at the Barstow, California and Las Vegas, Nevada terminals, and from higher diesel lubricity additive injection service revenues. The $5.0 million increase in revenues in 2005 versus 2004 consisted of a $2.9 million (7%) increase from refined products delivery revenues, primarily due to volume growth, and a $2.1 million (19%) increase from terminal operations, due to higher product storage, injection and ethanol blending services;

·

increases of $3.8 million (10%) and $2.8 million (8%), respectively, from the Central Florida Pipeline. The 2006 increase was due to a 10% increase in average tariff rates compared to 2005. The increased rates reflect reductions in zone-based credits in 2006 versus 2005. The year-to-year increase in revenues in 2005 compared to 2004 was due to an 8% increase in transport volumes, partly due to hurricane-related pipeline delivery disruptions in the State of Florida during the third quarter of 2004;

·

increases of $2.5 million (6%) and $1.4 million (3%), respectively, from the North System. The 2006 increase was due to higher natural gas liquids delivery revenues in 2006 versus 2005, driven by a 5% increase in system throughput volumes. The volume increase was primarily related to additional refinery demand in 2006 versus 2005.

·

The 2005 increase was due to higher average tariff rates, which more than offset a drop in revenues caused by a decline in delivery volumes. The increase in tariff rates in 2005 over 2004 resulted from both a higher ratio of long haul shipments to shorter haul shipments and, to a lesser extent, higher published tariff rates that were approved by the FERC and became effective April 1, 2005. The new rates were associated with a cost of service filing that was approved by the FERC. The decline in volumes was mainly related to lower propane demand due to warmer winter weather in the Midwest during 2005 relative to 2004; and

·

decreases of $0.5 million (1%) and $1.8 million (5%), respectively, from Kinder Morgan Energy Partners’ ownership interest in the Cochin pipeline system, as described above.  

Combining all of the segment’s operations, total delivery volumes of refined petroleum products decreased 0.8% in 2006 compared to 2005, but increased 0.4% in 2005 compared to 2004. Compared to last year, the Pacific operations’ total delivery volumes were up 1.7%, due in part to the East Line expansion, which was in service for the last seven months of 2006. The expansion project substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona. In addition, the CALNEV Pipeline delivery volumes were up 4.2% in 2006 versus 2005, due primarily to strong demand from the Southern California and Las Vegas, Nevada markets. The overall decrease in year-to-year segment deliveries of refined products was largely related to a 6.8% drop in volumes from the Plantation Pipeline in 2006, as described above. Compared to 2005, total deliveries of natural gas liquids increased 4.0% in 2006, driven by the higher volumes on the North System.

For 2005, the overall increase in delivery volumes compared with 2004 included increases on Pacific, Central Florida and CALNEV, offset by a decrease on Plantation. Excluding Plantation, which was impacted by Gulf Coast hurricanes and post-hurricane refinery disruptions in 2005, refined products delivery volumes increased 2.5% in 2005 compared to 2004. By product, deliveries of gasoline, diesel fuel and jet fuel increased 1.6%, 5.0% and 2.6%, respectively, in 2005 compared to 2004. Year-to-year deliveries of natural gas liquids were down 15% in 2005 versus 2004. The decrease was due to low demand for propane on both the North System and the Cypress Pipeline. The drop in demand on the North System was primarily due to a minimal grain drying season and to warmer weather in 2005; the drop on Cypress was chiefly due to reduced demand from a petrochemical plant located in Lake Charles, Louisiana, resulting from hurricane-related closures in 2005.

The segment’s operating expenses, which consist of all cost of sales expenses, operating and maintenance expenses, fuel and power expenses, and all tax expenses, excluding income taxes, decreased $57.8 million (16%) in 2006 versus 2005 and increased $144.0 million (65%) in 2005 versus 2004. Combined, the net effect attributable to four items previously discussed: (i) the expensing of pipeline integrity costs in 2006; (ii) the adjusting of segment environmental liability balances in 2006, 2005 and 2004; (iii) the adjusting of the Pacific operations’ pipeline rate case liability in 2005; and (iv) the expensing of inventory costs associated with the reconciliation of the North System’s inventory balances in 2005, resulted in a $104.7 million decrease in operating expenses in 2006 relative to 2005, and a $107.6 million increase in operating expenses in 2005 relative to 2004.

The remaining year-over-year increases of $46.9 million (21%) in 2006 compared to 2005 and $36.4 million (19%) in 2005 compared to 2004, primarily consisted of the following:



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Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




·

increases of $19.6 million (82%) and $14.5 million (153%), respectively, from the Southeast terminals. The 2006 increase was largely attributable to higher costs of sales related to higher ethanol blending and higher ethanol and liquids purchases (offset by higher ethanol revenues). The 2005 increase was primarily due to incremental expenses related to the terminal operations Kinder Morgan Energy Partners acquired in 2004—including expenses of $13.0 million attributable to the Charter terminals Kinder Morgan Energy Partners acquired in November 2004, and $0.9 million attributable to the ExxonMobil terminals Morgan Energy Partners acquired in March 2004;

·

increases of $18.3 million (18%) and $11.7 million (13%), respectively, from the combined Pacific and CALNEV Pipeline operations. The 2006 increase was due to a lower capitalization of expenses, relative to 2005, higher fuel and power, and higher remedial and repair expenses. The decrease in capitalized costs was primarily due to the expensing of pipeline integrity management costs in 2006, versus capitalizing such costs in the prior year. The increase in fuel and power expenses was due to higher refined products delivery volumes and higher average utility rates in 2006, and to a utility rebate credit received in the first quarter of 2005. The increase in pipeline repair expenses was largely related to pipeline failures and releases that have occurred since the end of 2005.

·

The $11.7 million increase in expenses in 2005 compared to 2004 was mainly due to higher labor and operating expenses, including incremental power expenses, associated with increased transportation volumes and terminal operations. The segment also incurred higher maintenance and inspection expenses during 2005 as a result of environmental issues, clean-up, and pipeline repairs associated with wash-outs that were caused by flooding in the State of California in the first quarter of 2005;

·

increases of $9.0 million (46%) and $1.6 million (9%), respectively, from the West Coast terminals. The increase in expenses in 2006 relative to 2005 was primarily related to incremental environmental expenses of $6.2 million (not related to the segment’s supplemental environmental liability adjustments in 2006) and to higher materials and supplies expense as a result of lower capitalized overhead. The increase in operating expenses in 2005 compared to 2004 was chiefly due to higher property tax expenses, described above, and higher cost of sales related to incremental terminal services;

·

increases of $0.2 million (2%) and $1.4 million (18%), respectively, from the Central Florida Pipeline operations. The increase in 2006 compared to 2005 was due to incremental environmental expenses (not related to the segment’s supplemental environmental liability adjustments in 2006). The increase in operating expenses in 2005 compared to 2004 was primarily due to higher maintenance expenses, due to additional expense accruals related to a pipeline release occurring in September 2005;

·

a decrease of $1.7 million (10%) and an increase of $2.9 million (22%), respectively, from Kinder Morgan Energy Partners’ proportionate interest in the Cochin Pipeline. The decrease in expenses in 2006 was mainly due to the drop in throughput volumes in 2006 compared to 2005. The increase in expenses in 2005 versus 2004 was primarily due to higher labor and outside services associated with pipeline maintenance and testing costs, and partly due to a full year’s inclusion of an additional 5% ownership interest in Cochin. Effective October 1, 2004, Kinder Morgan Energy Partners acquired an additional undivided 5% interest in the Cochin pipeline system for approximately $10.9 million, bringing its total interest to 49.8%; and

·

a decrease of $0.5 million (3%) and an increase of $2.9 million (16%), respectively, from the North System. The 2006 decrease was due to both higher product gains and lower fuel and power expenses relative to 2005, partly offset by higher property tax expenses related to an expense true-up recognized in the third quarter of 2006. The 2005 increase was primarily due to higher liquids storage expenses in 2005, as discussed above.

Earnings from Products Pipelines - KMP’s equity investments were $16.3 million in 2006, $28.4 million in 2005 and $29.1 million in 2004. Earnings from equity investments consist primarily of Kinder Morgan Energy Partners’ approximate 51% interest in the pre-tax income of Plantation Pipe Line Company and Kinder Morgan Energy Partners’ 50% interest in the net income of Heartland Pipeline Company and Johnston County Terminal, LLC. We include Kinder Morgan Energy Partners’ proportionate share of Plantation’s income tax expenses within “Income taxes” in the accompanying Consolidated Statements of Operations, and the interest income Kinder Morgan Energy Partners earns on loans to Plantation are reported within “Interest Expense, Net” in the accompanying Consolidated Statements of Operations.

The $12.1 million (43%) decrease in equity earnings in 2006 compared to 2005 was mainly due to lower equity earnings from Plantation, due to both a $6.6 million decrease for Kinder Morgan Energy Partners’ proportionate share of Plantation’s pre-tax pipeline integrity expenses that were recognized in the second half of 2006, and a $4.9 million decrease for Kinder Morgan Energy Partners’ proportionate share of pre-tax environmental expenses recognized by Plantation in the second quarter of 2006. This environmental expense was related to supplemental environmental and clean-up liability adjustments associated with an April 17, 2006 pipeline release of turbine fuel from Plantation’s 12-inch petroleum products pipeline located in Henrico County, Virginia.



84



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




The $0.7 million (2%) decrease in equity earnings in 2005 compared to 2004 primarily consisted of a $1.3 million (5%) decrease related to Kinder Morgan Energy Partners’ investment in Plantation and a $0.8 million (55%) increase related to Kinder Morgan Energy Partners’ investment in Heartland. For the investment in Plantation, the decrease was due to lower overall pre-tax income earned by Plantation, due to, among other things, higher operating expenses and higher interest expenses. For the investment in Heartland, the increase was due to Heartland’s higher net income, primarily due to higher pipeline delivery volumes in 2005 versus 2004.

The segment’s income from allocable interest income and other income and expense items increased $5.9 million (97%) in 2006 compared to 2005, and increased $1.4 million (31%) in 2005 compared to 2004. The 2006 increase was primarily due to the $5.7 million other income item from the favorable settlement of transmix processing contracts in the second quarter of 2006, and partly due to higher administrative overhead collected by the West Coast terminals from reimbursable projects. For 2005, the increase primarily related to incremental interest income of $2.5 million on the long-term note receivable from Plantation, as discussed above.

Income tax expenses decreased $5.2 million (50%) in 2006 compared to 2005, and decreased $1.7 million (14%) in 2005 compared to 2004. The decrease in 2006 versus 2005 was related to the lower pre-tax earnings from Cochin and Plantation, and the decrease in 2005 versus 2004 was mainly due to lower income tax on Cochin due to the decrease in Canadian operating results in 2005.

Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments, were $86.3 million, $82.5 million and $74.5 million in each of the years ended December 31, 2006, 2005 and 2004, respectively. The $3.8 million (5%) increase in 2006 compared to 2005 was primarily due to higher depreciation expenses from the Pacific and Southeast terminal operations. The increase from the Pacific operations related to higher depreciable costs as a result of capital spending for both pipeline and storage expansion since the end of 2005 in order to strengthen and enhance the business operations on the West Coast. The increase from the Southeast terminal operations related to incremental depreciation charges resulting from final purchase price allocations, made in the fourth quarter of 2005, for depreciable terminal assets Kinder Morgan Energy Partners acquired in November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC.

The overall $8.0 million (11%) increase in depreciation expenses in 2005 compared to 2004 was primarily due to higher depreciation expenses from the Pacific operations, related to the capital investments made since the end of 2004, as well as to incremental depreciation expenses of $1.8 million related to the Southeast terminal assets Kinder Morgan Energy Partners acquired in March and November 2004.

Natural Gas Pipelines – KMP

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions, except operating statistics)

  Revenues

$

6,577.7

 

 

$

7,718.4

 

 

$

6,252.9

 

  Operating Expenses (Including Environmental
Adjustments)
a

 

(6,042.6

)

 

 

(7,255.0

)

 

 

(5,854.6

)

  Earnings from Equity Investments

 

40.4

 

 

 

36.8

 

 

 

20.0

 

  Interest Income and Other, Net – Income (expense)

 

0.8

 

 

 

2.7

 

 

 

1.8

 

  Income taxes

 

(1.5

)

 

 

(2.6

)

 

 

(1.8

)

Earnings before Depreciation, Depletion and
Amortization Expense and Amortization of Excess
Cost of Equity Investments

 

574.8

 

 

 

500.3

 

 

 

418.3

 

 

 

 

 

 

 

 

 

 

 

 

 

  Depreciation, Depletion and Amortization Expense

 

(65.4

)

 

 

(61.6

)

 

 

(53.1

)

  Amortization of Excess Cost of Equity Investments

 

(0.3

)

 

 

(0.3

)

 

 

(0.3

)

    Segment Earnings

$

509.1

 

 

$

438.4

 

 

$

364.9

 

 

 

 

 

 

 

 

 

 

 

 

 

  Natural Gas Transport Volumes (Trillion Btus)b

 

1,440.9

 

 

 

1,317.9

 

 

 

1,353.1

 

  Natural Gas Sales Volumes (Trillion Btus)c

 

909.3

 

 

 

924.6

 

 

 

992.4

 

_____________


a

2006 amount includes expense of $1.5 million associated with supplemental environmental liability adjustments, a $6.2 million reduction in expense due to the release of a reserve related to a natural gas pipeline contract obligation and a gain of $15.1 million from the combined sale of our Douglas natural gas gathering system and Painter Unit fractionation



85



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




facility. 2005 and 2004 amounts include decreases in expense of $0.1 million and $7.6 million, respectively, associated with environmental liability adjustments.

b

Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural gas pipeline group, Trailblazer and TransColorado pipeline volumes. TransColorado annual volumes are included for all three years (acquisition date November 1, 2004).

c

Represents Texas intrastate natural gas pipeline group.

Due to the adoption of EITF 04-5 (see Note 1(B) of the accompanying Notes to Consolidated Financial Statements), effective January 1, 2006, we include the results of operations of Kinder Morgan Energy Partners in our consolidated results of operations. Although we accounted for Kinder Morgan Energy Partners under the equity method during 2005 and 2004, for comparative purposes, the following discussion regarding the segment results of the Natural Gas Pipelines – KMP business segment includes segment results for 2006, 2005 and 2004.

The Natural Gas Pipelines – KMP segment’s primary businesses involve marketing, transporting, storing, gathering and processing natural gas through both intrastate and interstate pipeline systems and related facilities. In 2006, the segment reported earnings before depreciation, depletion and amortization of $574.8 million on revenues of $6,577.7 million. This compares with earnings before depreciation, depletion and amortization of $500.3 million on revenues of $7,718.4 million in 2005 and earnings before depreciation, depletion and amortization of $418.3 million on revenues of $6,252.9 million in 2004.

Segment Earnings before Depreciation, Depletion and Amortization

The segment’s overall $74.5 million (15%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $82.0 million (20%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 included an increase of $19.8 million and a decrease of $7.6 million, respectively, from the combined net effect of the certain other items described in footnote (a) to the table above. These items consisted of the following:

·

an increase in earnings of $15.1 million in 2006—due to the sale of the Douglas natural gas gathering system and Painter Unit fractionation facility in April 2006. Effective April 1, 2006, Kinder Morgan Energy Partners sold these two assets to a third party for approximately $42.5 million in cash, and we included a net gain of $15.1 million within “Other Expense (Income)” in our accompanying Consolidated Statement of Operations for 2006. For more information on this gain, see Note 5 of the accompanying Notes to Consolidated Financial Statements;

·

an increase in earnings of $6.2 million in 2006—due to release of a reserve related to a natural gas purchase/sales contract associated with the operations of the West Clear Lake natural gas storage facility located in Harris County, Texas. Kinder Morgan Energy Partners acquired this storage facility as part of its acquisition of Kinder Morgan Tejas on January 31, 2002, and, upon acquisition, established a reserve for a contract liability; and

·

a decrease in earnings of $1.5 million in 2006 and an increase in earnings of $7.6 million in 2004—due to changes in environmental operating expenses associated with the adjustments of our environmental liabilities as more fully described above in “Critical Accounting Policies and Estimates—Environmental Matters.”

The segment’s remaining $54.7 million (11%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 was driven by higher earnings from the Texas intrastate natural gas pipeline group, primarily from improved margins resulting from the negotiation of renewal and incremental gas purchase and sales contracts, and by higher earnings from natural gas storage and processing activities. The Texas intrastate group includes the operations of the following four natural gas pipeline systems: Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan Texas Pipeline, Kinder Morgan North Texas Pipeline and the Mier-Monterrey Mexico Pipeline. Combined, the group accounted for 55% of the total increase in segment earnings before depreciation, depletion and amortization in 2006 versus 2005.

The segment’s remaining $89.6 million (22%) increase in earnings in 2005 compared with 2004 was mainly due to higher margins on recurring natural gas sales business and higher storage and service revenues from the Texas intrastate group, and to incremental contributions from the inclusion of the TransColorado Pipeline, a 300-mile interstate natural gas pipeline system that extends from the Western Slope of Colorado to the Blanco natural gas hub in northwestern New Mexico. Kinder Morgan Energy Partners acquired the TransColorado Pipeline from Kinder Morgan, Inc. on November 1, 2004, and the incremental amounts above relate to TransColorado’s operations during the first ten months of 2005 and do not include increases or decreases during the same two months Kinder Morgan Energy Partners owned the asset in both 2005 and 2004.

Specifically, the respective remaining changes in year-to-year segment earnings before depreciation, depletion and amortization expense in 2006 versus 2005, and 2005 versus 2004, consisted of the following:



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KMI Form 10-K

    




·

increases of $34.6 million (13%) and $30.1 million (13%), respectively, from the Texas intrastate natural gas pipeline group—due primarily to improved margins on the group’s natural gas purchase and sales activities, described above. With regard to natural gas sales activities, margin is defined as the difference between the prices at which we buy gas in our supply areas and the prices at which we sell gas in our market areas, less the cost of fuel to transport. In 2006, the Texas intrastate group’s’ natural gas sales margin increased $48.0 million (34%) over 2005; and in 2005, the group’s’ margin increased $30.7 million (28%) over 2004. The group’s margin can vary depending upon, among other things, the price volatility of natural gas produced and delivered in Texas and in the surrounding Gulf Coast region, the changes in availability and demand for transportation and storage capacities, and any changes in the terms and conditions in which natural gas is purchased and sold.

Additionally, we manage price risk associated with unfavorable changes in natural gas prices by using energy derivative contracts, such as over-the-counter forward contracts and both fixed price and basis swaps, to help lock-in favorable margins from natural gas purchase and sales activities, thereby generating more stable earnings during periods of fluctuating natural gas prices;

·

increases of $10.2 million (10%) and $2.4 million (2%), respectively, from the Kinder Morgan Interstate Gas Transmission system. The increase in 2006, relative to 2005, was due largely to higher revenues earned in 2006 from both operational sales of natural gas and natural gas park and loan services. The increase in 2006 earnings from these incremental revenues more than offset a relative decrease in earnings resulting from favorable natural gas imbalance valuation adjustments recognized in 2005.

The increase in earnings in 2005 compared to 2004 was due mainly to higher revenues from both favorable fuel recovery volumes and prices and favorable imbalance valuation adjustments. In addition, KMIGT realized lower operating expenses in 2005 compared to 2004, primarily due to the expensing, in the fourth quarter of 2004, of certain capitalized project costs that no longer held realizable economic benefits. The increase in revenues in 2005 versus 2004 was partially offset by lower margins on operational gas sales and reduced cushion gas volumes sold;

·

increases of $4.3 million (13%) and $17.3 million (119%), respectively, from Kinder Morgan Energy Partners’ 49% equity investment in Red Cedar Gathering Company—due largely to higher natural gas gathering revenues and to higher prices on incremental sales of excess fuel gas. Additionally, since the end of 2004, Kinder Morgan Energy Partners reduced the amount of natural gas lost and used within the system during gathering operations, which in turn has increased natural gas volumes available for sale;

·

increases of $3.8 million (10%) and $33.4 million respectively, from the TransColorado Pipeline—the 2006 increase was largely due to higher natural gas transmission revenues earned in 2006 compared to 2005. The revenue increase related to higher natural gas delivery volumes resulting from both system improvements and the successful negotiation of incremental firm transportation contracts. The pipeline system improvements were associated with an expansion, completed since the end of the first quarter of 2005, on the northern portion of the pipeline. TransColorado’s north system expansion project was in-service on January 1, 2006, and provides for up to 300 million cubic feet per day of additional northbound transportation capacity. The overall increase in earnings in 2005 compared to 2004 was primarily due to incremental earnings of $31.8 million, representing TransColorado’s earnings before depreciation, depletion and amortization expenses in the first ten months of 2005 (after acquiring the pipeline on November 1, 2004);

·

an increase of $2.3 million (21%) and a decrease of $5.1 million (32%), respectively, from the combined operations of the Casper Douglas and Painter natural gas gathering and processing operations. The 2006 increase in earnings was primarily related to incremental earnings associated with favorable hedge settlements from the Casper Douglas natural gas gathering and processing operations. Kinder Morgan Energy Partners benefited from comparative differences in hedge settlements associated with the rolling-off of older low price crude oil and propane positions at December 31, 2005. The 32% decrease in earnings in 2005 versus 2004 was mainly due to higher cost of sales expense and higher commodity hedging costs in 2005. The higher cost of sales expense reflected higher natural gas purchase costs, due to higher average gas prices in 2005. The higher commodity hedging costs was chiefly due to unfavorable changes in settlement prices;

·

increases of $0.3 million (1%) and $10.9 million (28%), respectively, from the Trailblazer Pipeline—due primarily to timing differences on the settlements of pipeline transportation imbalances in 2006 and 2005, compared to the respective year-earlier periods. These pipeline imbalances are due to differences between the volumes received and the volumes delivered at inter-connecting points on the pipeline, and generally, the imbalances are either settled in cash or made up in kind subject to both the pipelines’ various tariff provisions and operational balancing agreements with shippers. The increase in earnings in 2006 compared to 2005 was also due to incremental sales of operational natural gas in the fourth quarter of 2006, largely related to timing differences; and



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Results of Operations. (continued)

KMI Form 10-K

    




·

a decrease of $0.8 million (13%) and an increase of $0.5 million (9%), respectively, from the combined earnings of the remaining natural gas operations, including Kinder Morgan Energy Partners’ previous 50% investment in Coyote Gas Treating, LLC and Kinder Morgan Energy Partners’ 25% investment in Thunder Creek Gas Services, LLC—the decrease in 2006 was due to both the absence of equity earnings from Kinder Morgan Energy Partners’ investment in Coyote and to lower natural gas gathering income from Thunder Creek. Effective September 1, 2006, Kinder Morgan Energy Partners and the Southern Ute Indian Tribe contributed the value of their respective 50% ownership interests in Coyote Gas Treating, LLC to Red Cedar, and as a result, Coyote Gas Treating, LLC became a wholly owned subsidiary of Red Cedar.

The increase in earnings in 2005 compared to 2004 was largely due to incremental interest income from Kinder Morgan Energy Partners’ long-term note receivable from Coyote. In 2005, Kinder Morgan Energy Partners allocated this interest income to the Natural Gas Pipelines - KMP business segment, versus treating it as unallocated interest income in 2004. In March 2006, Kinder Morgan Energy Partners contributed the principal amount of $17.0 million related to this note to its equity investment in Coyote.

Segment Details

In 2006, total segment operating revenues, including revenues from natural gas sales, decreased $1,140.7 million (15%) compared to 2005, and combined operating expenses, including natural gas purchase costs, decreased $1,212.3 million (17%). In 2005, the segment reported significant increases in both revenues and operating expenses when compared to the year-earlier period—revenues increased $1,465.5 million (23%) and operating expenses increased $1,400.4 million (24%). The year-to-year changes in total segment revenues and total segment operating expenses largely represented the respective changes in the Texas intrastate group’s natural gas sales revenues and natural gas purchase expenses, due primarily to year-over-year changes in natural gas prices.

The Intrastate group’s purchase and sale activities result in considerably higher revenues and operating expenses compared to the interstate operations of the Rocky Mountain pipelines, which include the KMIGT, Trailblazer and TransColorado pipelines. All three pipelines charge a transportation fee for gas transmission service and have the authority to initiate natural gas sales primarily for operational purposes, but none engage in significant gas purchases for resale. Kinder Morgan Energy Partners did, however, realize incremental revenues of $36.2 million and incremental operating expenses of $4.5 million from the ownership of the TransColorado Pipeline in the first ten months of 2005.

As discussed above, the Texas intrastate group both purchases and sells significant volumes of natural gas. Compared to the respective prior year, revenues from the sales of natural gas from the Intrastate group decreased $1,154.4 million (16%) in 2006, and increased $1,404.1 million (24%) in 2005; similarly, the group’s costs of sales expense, including natural gas purchase costs, decreased $1,202.4 million (17%) in 2006, and increased $1,373.4 million (24%) in 2005.  

Since the Texas intrastate group sells natural gas in the same price environment in which it is purchased, any increases in its gas purchase costs are largely offset by corresponding increases in its sales revenues. Due to this offsetting of revenues and expenses, we believe that margin is a better comparative performance indicator than either revenues or cost of sales, and our objective is to match purchases and sales in the aggregate, and to lock-in an acceptable margin by capturing the difference between our average gas sales prices and our average gas purchase and cost of fuel prices. Our strategy involves relying mainly on long-term natural gas sales and purchase agreements, with some purchases and sales being made in the spot market in order to provide some flexibility to balance supply and demand in reaction to changing market conditions.

The Texas intrastate groups’ natural gas sales margin increased $48.0 million (34%) and $30.7 million (28%), respectively, in 2006 and 2005, when compared to the year-earlier period. The variations in natural gas sales margin were driven by changes in natural gas prices and sales volumes—the $48.0 million margin increase in 2006 consisted of a $59.3 million increase from favorable changes in average sales versus average purchase prices (favorable price variance), and a $11.3 million decrease from lower volumes (unfavorable volume variance)—the $30.7 million margin increase in 2005 consisted of a $40.0 million increase from favorable changes in average sales prices versus average purchase prices, and a $9.3 million decrease from lower volumes. Also, the intrastate groups’ margins from natural gas processing activities increased $10.1 million (53%) in 2006 compared to 2005, and decreased $3.8 million (17%) in 2005 compared to 2004.

Kinder Morgan Energy Partners accounts for the segment’s investments in Red Cedar Gathering Company, Thunder Creek Gas Services, LLC, and prior to September 1, 2006, Coyote Gas Treating, LLC under the equity method of accounting. Combined earnings from these three investees increased $3.6 million (10%) and $16.9 million (84%), respectively, in 2006 and 2005, when compared to year-earlier periods. The increases were chiefly due to higher net income earned by Red Cedar during 2006 and 2005, partially offset by lower net income from the combined investments in Coyote Gas Treating LLC and Thunder Creek Gas Services, LLC, all discussed above.

The segment’s combined interest income and earnings from other income items (Other, Net) decreased $2.0 million (72%) in



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Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




2006 compared to 2005, and increased $0.9 million in 2005 compared to 2004. The 2006 decrease was chiefly due to a gain from a property disposal by the Kinder Morgan Tejas Pipeline in the third quarter of 2005. The 2005 increase was mainly due to the allocation of interest income earned, in 2005, on Kinder Morgan Energy Partners’ note receivable from Coyote Gas Treating, LLC. Income tax expenses changed slightly over both 2006 and 2005—decreasing $1.2 million (46%) in 2006, and increasing $0.7 million (38%) in 2005, when compared to prior years. The changes primarily related to tax accrual adjustments related to the operations of the Mier-Monterrey Mexico Pipeline.

The segment’s non-cash depreciation, depletion and amortization charges, including amortization of excess cost of investments increased $3.7 million (6%) in 2006 compared to 2005, and increased $8.5 million (16%) in 2005 compared to 2004. The 2006 increase was largely attributable to higher year-to-year depreciation expenses from the Texas intrastate natural gas pipeline group, due both to incremental capital spending during 2006, and to additional depreciation charges related to the group’s acquisition of the North Dayton, Texas natural gas storage facility in August 2005. The 2005 increase was due to incremental depreciation expenses of $4.2 million from the inclusion of the acquired TransColorado Pipeline, and higher depreciation expenses on the assets of the Texas intrastate natural gas pipeline group, due to additional capital investments made since the end of 2004.

CO2 – KMP

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions, except operating statistics)

Revenuesa

$

736.5

 

 

$

657.6

 

 

$

492.8

 

Operating Expenses (Including Environmental
Adjustments)
b

 

(268.1

)

 

 

(212.6

)

 

 

(169.3

)

Earnings from Equity Investments

 

19.2

 

 

 

26.3

 

 

 

34.2

 

Other, Net – Income (Expense)

 

0.8

 

 

 

-

 

 

 

-

 

Income Taxes

 

(0.2

)

 

 

(0.4

)

 

 

(0.1

)

Earnings before Depreciation, Depletion and
Amortization Expense and Amortization of Excess
Cost of Equity Investments

 

488.2

 

 

 

470.9

 

 

 

357.6

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, Depletion and Amortization Expensec

 

(191.0

)

 

 

(149.9

)

 

 

(121.3

)

Amortization of Excess Cost of Equity Investments

 

(2.0

)

 

 

(2.0

)

 

 

(2.0

)

Segment Earnings

$

295.2

 

 

$

319.0

 

 

$

234.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Carbon Dioxide Delivery Volumes (Bcf)d

 

669.2

 

 

 

649.3

 

 

 

640.8

 

SACROC Oil Production (Gross)(MBbl/d)e

 

30.8

 

 

 

32.1

 

 

 

28.3

 

SACROC Oil Production (Net)(MBbl/d)f

 

25.7

 

 

 

26.7

 

 

 

23.6

 

Yates Oil Production (Gross)(MBbl/d)e

 

26.1

 

 

 

24.2

 

 

 

19.5

 

Yates Oil Production (Net)(MBbl/d)f

 

11.6

 

 

 

10.8

 

 

 

8.6

 

Natural Gas Liquids Sales Volumes (Net)(MBbl/d)f

 

8.9

 

 

 

9.4

 

 

 

7.7

 

Realized Weighted Average Oil Price per Bblg, h

$

31.42

 

 

$

27.36

 

 

$

25.72

 

Realized Weighted Average Natural Gas Liquids Price
per Bbl
h, i

$

43.90

 

 

$

38.98

 

 

$

31.33

 

_____________


a

2006 includes a $1.8 million loss on derivative contracts used to hedge forecasted crude oil sales.

b

Includes expense of $0.3 million in 2005 and a decrease in expense of $4.1 million in 2004 associated with environmental liability adjustments.

c

Includes depreciation, depletion and amortization expense associated with oil and gas producing and gas processing activities in the amount of $171.3 million for 2006, $132.3 million for 2005, and $105.9 million for 2004. Includes depreciation, depletion and amortization expense associated with sales and transportation services activities in the amount of $19.6 million for 2006, $17.6 million for 2005, and $15.5 million for 2004.

d

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

e

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

f

Net to Kinder Morgan, after royalties and outside working interests.

g

Includes all Kinder Morgan crude oil production properties.



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KMI Form 10-K

    




h

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

i

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

Due to the adoption of EITF 04-5 (see Note 1(B) of the accompanying Notes to Consolidated Financial Statements), effective January 1, 2006, we include the results of operations of Kinder Morgan Energy Partners in our consolidated results of operations. Although we accounted for Kinder Morgan Energy Partners under the equity method during 2005 and 2004, for comparative purposes, the following discussion regarding the segment results of the CO2 – KMP business segment includes segment results for 2006, 2005 and 2004.

The CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. The segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids. In 2006, the CO2 segment reported earnings before depreciation, depletion and amortization of $488.2 million on revenues of $736.5 million. This compares with earnings before depreciation, depletion and amortization of $470.9 million on revenues of $657.6 million in 2005, and earnings before depreciation, depletion and amortization of $357.6 million on revenues of $492.8 million in 2004.

The segment’s overall $17.3 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $113.3 million (32%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 included decreases of $1.5 million and $4.4 million, respectively, from the combined net effect of the certain other items described in footnotes (a) and (b) to the table above. These items consisted of the following:

·

a decrease in earnings of $1.8 million in 2006—due to a $1.8 million loss on derivative contracts used to hedge forecasted crude oil sales; and

·

a decrease in earnings of $0.3 million in 2005 and an increase in earnings of $4.1 million in 2004—due to changes in environmental operating expenses associated with the adjustments of our environmental liabilities.

The segment’s remaining $18.8 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 was driven by higher earnings from the segment’s carbon dioxide sales and transportation activities; the remaining $117.7 million (33%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004 was primarily due to higher earnings from the segment’s oil and gas producing activities.

Segment Earnings before Depreciation, Depletion and Amortization

Sales and Transportation Activities

The segment’s carbon dioxide sales and transportation activities reported earnings before depreciation, depletion and amortization of $186.8 million in 2006, $162.4 million in 2005, and $123.6 million in 2004. The increases in earnings were driven by higher revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation. The overall increases were partly offset by lower equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company.

The increases in carbon dioxide sales revenues were due to both higher average prices and higher sales volumes. Correlating closely with the increase in crude oil prices since the end of 2004, average carbon dioxide sales prices increased 18% and 44%, respectively, in 2006 and 2005, when compared to the prior year. In addition, we did not use derivative contracts to hedge or help manage the financial impacts associated with the increases in carbon dioxide prices, and as always, we did not recognize profits on carbon dioxide sales to ourselves.

The increases in volumes were largely attributable to the continued strong demand for carbon dioxide from tertiary oil recovery projects in the Permian Basin area since the end of 2004, and to increased carbon dioxide production from the McElmo Dome source field. Kinder Morgan Energy Partners operates and owns a 45% interest in McElmo Dome, which supplies carbon dioxide to oil recovery fields in the Permian Basin of southeastern New Mexico and West Texas. Combined deliveries of carbon dioxide on the Central Basin Pipeline, the majority-owned Canyon Reef Carriers and Pecos Pipelines, the Centerline Pipeline, and the 50% owned Cortez Pipeline, which is accounted for under the equity method of accounting, increased 3% in 2006 and 1% in 2005, when compared to the respective prior years.

The increases in revenues from carbon dioxide and crude oil transportation were due to higher delivery volumes and higher rates. The increase in volumes was largely related to infrastructure expansions at the SACROC and Yates oil field units. The SACROC and Yates units are the two largest oil field units in which Kinder Morgan Energy Partners holds ownership interests—these interests include the approximate 97% working interest in the SACROC unit, located in Scurry County,



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Results of Operations. (continued)

KMI Form 10-K

    




Texas, and the approximate 50% working interest in the Yates unit, located south of Midland, Texas.

In 2005, Kinder Morgan Energy Partners also benefited from the acquisition of the Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline system originating in the Permian Basin of West Texas and providing throughput to a crude oil refinery located in El Paso, Texas. Effective August 31, 2004, Kinder Morgan Energy Partners acquired all of the partnership interests in Kinder Morgan Wink Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4 million in liabilities. The acquisition of the pipeline and associated storage facilities allowed Kinder Morgan Energy Partners to better manage crude oil deliveries from its oil field interests in West Texas. During the first eight months of 2005, the Kinder Morgan Wink Pipeline accounted for incremental earnings before depreciation, depletion and amortization of $13.4 million, revenues of $16.7 million and operating expenses of $3.3 million.

Oil and Gas Producing Activities

The remaining changes in year-to-year segment earnings before depreciation, depletion and amortization—a decrease of $7.1 million (2%) in 2006 versus 2005, and an increase of $74.5 million (32%) in 2005 versus 2004, were attributable to the segment’s crude oil and natural gas producing activities, which also include its natural gas processing activities. These operations include all construction, drilling and production activities necessary to produce oil and gas from its natural reservoirs, and all of the activities where natural gas is processed to extract liquid hydrocarbons, called natural gas liquids or commonly referred to as gas plant products. Combined, the CO2 – KMP segment’s oil and gas producing and gas processing activities reported earnings before depreciation, depletion and amortization of $301.4 million in 2006, $308.5 million in 2005, and $234.0 million in 2004.

In both 2006 and 2005, Kinder Morgan Energy Partners made significant capital investments to increase the capacity and deliverability of carbon dioxide and crude oil in and around the Permian Basin. These investments were made in order to benefit from rising price trends for energy commodity products and from continued strong demand for carbon dioxide from tertiary oil recovery projects, which commonly inject carbon dioxide into reservoirs adjacent to producing crude oil wells. Once injected into the reservoir, the carbon dioxide gas often enhances crude oil recovery in two ways—first, by expanding and pushing additional oil to the production wellbore, and secondly, by dissolving into the oil in order to lower its viscosity and improve its flow rate. In 2006, capital expenditures for the CO2 – KMP business segment totaled $283.0 million; this compares with capital expenditures of $302.1 million in 2005 and $302.9 million in 2004. The expenditures primarily represent incremental spending for new well and injection compression facilities at the SACROC and, to a lesser extent, Yates oil field units.

The year-over-year $7.1 million (2%) decrease in earnings in 2006 compared to 2005 was primarily due to higher combined operating expenses and to an expected drop in crude oil production at the SACROC oil field unit. The higher operating expenses included higher field operating and maintenance expenses (including well workover expenses), higher property and severance taxes, and higher fuel and power expenses. The increases in expenses more than offset higher overall crude oil and natural gas plant product sales revenues, which increased primarily from higher realized sales prices and partly from higher crude oil production at the Yates oil field unit. The year-over-year increase in earnings of $74.5 million (32%) in 2005 compared to 2004 was primarily driven by increased crude oil and natural gas processing plant liquids production volumes, and by higher realized weighted average sale prices for crude oil and gas plant products.

The year-to-year decline in crude oil production at the SACROC unit in 2006 was announced in the first quarter of 2006. At that time, we used information obtained from production performance to change our previous estimates of proved crude oil reserves at SACROC; however, due to the fact that the decrease in production is largely specific to one section of the field that is underperforming, we do not expect this reserve revision to have a material impact on our financial statements or capital spending in future periods. For more information on Kinder Morgan Energy Partners’ ownership interests in the net quantities of proved oil and gas reserves and the measures of discounted future net cash flows from oil and gas reserves.

As a result of Kinder Morgan Energy Partners’ carbon dioxide and oil reserve ownership interests, it are exposed to commodity price risk associated with physical crude oil and natural gas liquids sales; however this price risk is mitigated through a long-term hedging strategy that uses derivative contracts to reduce the impact of unpredictable changes in crude oil and natural gas liquids sales prices. The goal is to use derivative contracts in order to prevent or reduce the possibility of future losses, and to generate more stable realized prices. Our hedging strategy involves the use of financial derivative contracts to manage this price risk on certain activities, including firm commitments and anticipated transactions for the sale of crude oil and natural gas liquids. Our strategy, as it relates to Kinder Morgan Energy Partners’ oil production business, primarily involves entering into a forward sale or, in some cases, buying a put option in order to establish a known price level. In this way, we use derivative contracts to lock in an acceptable margin between Kinder Morgan Energy Partners’ production costs and the selling price, in an attempt to protect against the risk of adverse price changes and to maintain a more stable and predictable earnings stream.

Had we not used energy derivative contracts to transfer commodity price risk, Kinder Morgan Energy Partners’ crude oil



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Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




sales prices would have averaged $63.27 per barrel in 2006, $54.45 per barrel in 2005 and $40.91 per barrel in 2004. In periods of rising prices for crude oil and natural gas liquids, we often surrender profits that would result from period-to-period price increases. We believe, however, that our use of derivative contracts protects Kinder Morgan Energy Partners’ unitholders from unpredictable adverse events. All of Kinder Morgan Energy Partners’ hedge gains and losses for crude oil and natural gas liquids are included in its realized average price for oil; none are allocated to natural gas liquids. For more information on our hedging activities, see Note 12 of the accompanying Notes to Consolidated Financial Statements.

Segment Details

Including the $1.8 million hedge ineffectiveness loss in 2006, the CO2 – KMP segment’s revenues increased $78.9 million (12%) in 2006 compared to 2005, and $164.8 million (33%) in 2005 compared to 2004. The respective year-over-year increases were primarily due to the following:

·

increases of $56.0 million (15%) and $71.7 million (23%), respectively, from crude oil sales—attributable to increases of 15% and 6%, respectively, in the realized weighted average price of crude oil and, in 2005, to a 16% increase in year-over-year sales volumes. The overall crude oil sales volumes were flat across both 2006 and 2005. On a gross basis, meaning total quantity produced, combined daily oil production from the SACROC and Yates units increased 1% in 2006 compared to 2005, and 18% in 2005 compared to 2004. In 2006, a 4% drop in crude oil production at SACROC was offset by an 8% increase in oil production at the Yates oil field unit. In 2005, gross crude oil production increased 13% at SACROC and 24% at Yates, when compared to 2004;

·

increases of $14.6 million (28%) and $26.1 million (103%), respectively, from carbon dioxide sales—due mainly to higher average sales prices, discussed above, and to year-over-year increases of 7% in sales volumes in both 2006 and 2005;

·

increases of $8.9 million (15%) and $18.0 million (44%), respectively, from carbon dioxide and crude oil pipeline transportation revenues—due largely to increases in system-wide carbon dioxide delivery volumes and, in 2005, to incremental crude oil transportation revenues from the Kinder Morgan Wink Pipeline;

·

increases of $7.9 million (6%) and $45.1 million (51%), respectively, from natural gas liquids sales—reflecting increases of 13% and 24%, respectively, in the realized weighted average natural gas liquids price per barrel. In 2005, Kinder Morgan Energy Partners also benefited from a 22% increase in liquids processing volumes, as compared to 2004, primarily due to the capital expenditures and infrastructure improvements made since the end of 2004. The 2006 increase in natural gas liquids sales was partially offset by a 5% decrease in sales volumes, primarily related to the lower crude oil production at SACROC; and

·

decreases of $10.4 million (72%) and $1.5 million (9%), respectively, from natural gas sales—due entirely to lower year-over-year sales volumes. The decreases in volumes were mainly attributable to lower volumes of gas available for sale since the second quarter of 2005, due partly to the overall declining production at the SACROC field and partly to natural gas volumes used at the power plant Kinder Morgan Energy Partners constructed at the SACROC oil field unit and placed in service in June 2005.

Construction of the plant began in mid-2004, and the project was completed at a cost of approximately $76 million. Kinder Morgan Energy Partners constructed the SACROC power plant in order to reduce its purchases of electricity from third-parties, but it reduces its sales of natural gas because some natural gas volumes are consumed by the plant. The power plant now provides approximately half of SACROC’s current electricity needs. Kinder Morgan, Inc. operates and maintains the power plant under a five-year contract expiring in June 2010, and Kinder Morgan Energy Partners reimburses Kinder Morgan, Inc. for its operating and maintenance costs.

Compared to the respective prior years, the segment’s operating expenses increased $55.5 million (26%) in 2006 and $43.4 million (26%) in 2005. The increases consisted of the following:

·

increases of $35.3 million (36%) and $7.7 million (9%), respectively, from combined cost of sales and field operating and maintenance expenses—largely due to additional labor and field expenses, including well workover expenses, related to infrastructure expansions at the SACROC and Yates oil field units since the end of 2004. Workover expenses relate to incremental operating and maintenance charges incurred on producing wells in order to restore or increase production, and are often performed in order to stimulate production, add pumping equipment, remove fill from the wellbore, or mechanically repair the well.

Oil and gas operations, coupled with carbon dioxide flooding, often require a high level of investment, including ongoing expenses for facility upgrades, wellwork and drilling. Kinder Morgan Energy Partners continues to aggressively pursue opportunities to drill new wells and/or expand existing wells for both carbon dioxide and crude



92



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




oil in order to benefit from robust demand for energy commodities in and around the Permian Basin area. In some cases, the cost of carbon dioxide that is associated with enhanced oil recovery is capitalized as part of the development costs when it is injected. The carbon dioxide costs incurred and capitalized as development costs for the CO2 segment were $100.5 million, $74.7 million and $70.6 million for the years ended December 31, 2006, 2005 and 2004, respectively;

·

increases of $13.8 million (19%) and $16.0 million (28%), respectively, from fuel and power expenses—due to increased carbon dioxide compression and equipment utilization, higher fuel costs, and higher electricity expenses due to higher rates as a result of higher fuel costs to electricity providers. Overall higher electricity costs were partly offset, however, by the benefits provided from the power plant Kinder Morgan Energy Partners constructed at the SACROC oil field unit;

·

increases of $6.7 million (16%) and $15.3 million (56%), respectively, from taxes, other than income taxes—attributable mainly to higher property and production (severance) taxes. The higher property taxes related to both increased asset infrastructure and higher assessed property values since the end of 2004. The higher severance taxes, which are primarily based on the gross wellhead production value of crude oil and natural gas, were driven by the higher period-to-period crude oil revenues; and

·

a decrease of $0.3 million and an increase of $4.4 million, respectively, due to changes in environmental operating expenses associated with the adjustments of our environmental liabilities.

Earnings from equity investments, representing equity earnings from the 50% ownership interest in the Cortez Pipeline Company, decreased $7.1 million (27%) in 2006 compared to 2005, and $7.9 million (23%) in 2005 compared to 2004. Cortez owns and operates an approximate 500-mile pipeline that carries carbon dioxide from the McElmo Dome source reservoir to the Denver City, Texas carbon dioxide hub. The decreases in equity earnings were due to lower year-over-year net income earned by Cortez since 2004, mainly as a result of lower carbon dioxide transportation revenues. The decreases in transportation revenues resulted from lower year-to-year average tariff rates, which more than offset incremental revenues realized as a result of higher carbon dioxide delivery volumes. The decreases in tariff rates were expected because Kinder Morgan Energy Partners benefited from higher tariffs in prior years, when tariffs were set higher in order to make up for under-collected revenues.

Non-cash depreciation, depletion and amortization charges, including amortization of excess cost of equity investments, increased $41.0 million (27%) in 2006 compared to 2005, and $28.5 million (23%) in 2005 compared to 2004. The increases were due to both higher depreciable costs, as a result of incremental capital spending since the end of 2004, and higher combined depreciation and depletion charges, related to year-over-year increases in crude oil production volumes. In 2006, Kinder Morgan Energy Partners also realized incremental depreciation charges of $3.4 million attributable to the various oil and gas properties acquired in April 2006 from Journey Acquisition – I, L.P. and Journey 2000, L.P.

The increase in depreciation expenses in 2006 compared to 2005 was also due to a higher unit-of-production depletion rate used in 2006, related to changes in estimated oil and gas reserves at the SACROC oil field unit. The capitalized costs of proved oil and gas properties must be amortized by the unit of production method so that each unit produced is assigned a pro rata portion of the unamortized costs. These amortization rates must be revised at least annually, but are also adjusted if there is an indication that total estimated units are different than previously estimated.



93



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Terminals – KMP

 

Year Ended December 31,

 

2006

 

2005

 

2004

 

(In millions, except operating statistics)

Revenues

$

864.8

 

 

$

699.3

 

 

$

541.8

 

Operating Expenses (Including Environmental
Adjustments)
a

 

(446.8

)

 

 

(373.4

)

 

 

(254.1

)

Earnings from Equity Investments

 

0.2

 

 

 

0.1

 

 

 

-

 

Other, Net – Income (Expense)

 

2.1

 

 

 

(0.3

)

 

 

(0.4

)

Income Taxesb

 

(12.2

)

 

 

(11.1

)

 

 

(5.6

)

Earnings Before Depreciation, Depletion and
Amortization Expense and Amortization of Excess
Cost of Equity Investments

 

408.1

 

 

 

314.6

 

 

 

281.7

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, Depletion and Amortization Expense

 

(74.5

)

 

 

(59.1

)

 

 

(42.9

)

Amortization of Excess Cost of Equity Investments

 

 

 

 

 

 

 

 

Segment Earnings

$

333.6

 

 

$

255.5

 

 

$

238.8

 

 

 

 

 

 

 

 

 

 

 

 

 

Bulk Transload Tonnage (MMtons)c

 

89.5

 

 

 

85.5

 

 

 

84.1

 

Liquids Leaseable Capacity (MMBbl)

 

43.5

 

 

 

42.4

 

 

 

36.8

 

Liquids Utilization %

 

96.3

%

 

 

95.4

%

 

 

96.0

%

_____________


a

2006 amount includes and increase in expense of $2.8 million related to hurricane clean-up and repair activities, and a gain of $15.2 million from property casualty indemnifications. Also, includes an increase in expense of $3.5 million in 2005 and a decrease in expense of $18.7 million in 2004 associated with environmental liability adjustments.

b

2006 amount includes expense of $1.1 million associated with hurricane expenses and casualty gain. 2004 amount includes expense of $0.1 million associated with environmental liability adjustments.

c

Volumes include all acquired terminals.

Due to the adoption of EITF 04-5 (see Note 1(B) of the accompanying Notes to Consolidated Financial Statements), effective January 1, 2006, we include the results of operations of Kinder Morgan Energy Partners in our consolidated results of operations. Although we accounted for Kinder Morgan Energy Partners under the equity method during 2005 and 2004, for comparative purposes, the following discussion regarding the segment results of the Terminals – KMP business segment includes segment results for 2006, 2005 and 2004.

The Terminals – KMP segment includes the operations of Kinder Morgan Energy Partners’ petroleum and petrochemical-related liquids terminal facilities (other than those included in the Products Pipelines – KMP segment), and all of Kinder Morgan Energy Partners’ coal, petroleum coke, steel and other dry-bulk material services facilities. Refining, manufacturing, mining and quarrying companies worldwide depend on these facilities to provide liquids and bulk handling services, transload, engineering, and other in-plant services to supply marine, rail, truck, temporary storage, and other distribution means needed to move dry-bulk, bulk petroleum, and chemicals across the United States. The segment reported earnings before depreciation, depletion and amortization of $408.1 million on revenues of $864.8 million in 2006. This compares with earnings before depreciation, depletion and amortization of $314.6 million on revenues of $699.3 million in 2005 and earnings before depreciation, depletion and amortization of $281.7 million on revenues of $541.9 million in 2004.

The segment’s overall $93.5 million (30%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005 and its $32.9 million (12%) increase in earnings before depreciation, depletion and amortization expenses in 2005 compared with 2004, included an increase of $14.8 million and a decrease of $22.1 million, respectively, from the combined net effect of the certain other items described in footnotes (a) and (b) to the table above. These items consisted of the following:

·

an increase in earnings of $11.3 million in 2006—from the combined effect of a gain from the settlement of property casualty insurance claims and incremental repair and clean-up expenses, both related to the 2005 hurricane season. In the third quarter of 2005, Hurricane Katrina struck the Louisiana-Mississippi Gulf Coast, and Hurricane Rita struck the Texas-Louisiana Gulf Coast, causing wide-spread damage to both residential and commercial property. The assets Kinder Morgan Energy Partners operates that were impacted by the storm included several bulk and liquids terminal facilities located in the States of Louisiana, Mississippi and Texas. Primarily affected was the International Marine Terminals facility, a Louisiana partnership owned 66 2/3% by Kinder Morgan Energy Partners. IMT is a multi-purpose bulk commodity transfer terminal facility located in Port Sulphur, Louisiana.



94



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




The $11.3 million increase in segment earnings consisted of: (i) a $15.2 million property casualty gain; (ii) a $2.8 million increase in operating and maintenance expenses from hurricane repair and recovery activities; and (iii) a $1.1 million increase in income tax expense associated with the segment’s overall hurricane income and expense items. Including an additional $0.4 million decrease in general and administrative expenses, and a $3.1 million increase in minority interest expense, both related to hurricane activity, total hurricane income and expense items increased Kinder Morgan Energy Partners’ net income by $8.6 million in 2006; and

·

a decrease in earnings of $3.5 million in 2005 and an increase in earnings of $18.6 million in 2004—due to changes in environmental operating expenses associated with the adjustments of our environmental liabilities.

The segment’s remaining $78.7 million (4%) increase in earnings before depreciation, depletion and amortization expenses in 2006 compared with 2005, and its remaining $55.0 million (21%) increase in 2005 compared to 2004 were driven by a combination of internal expansions and strategic acquisitions. Kinder Morgan Energy Partners makes and continues to seek key terminal acquisitions in order to gain access to new markets, to complement and/or enlarge its existing terminal operations, and to benefit from the economies of scale resulting from increases in storage, handling and throughput capacity.

Segment Earnings before Depreciation, Depletion and Amortization

Kinder Morgan Energy Partners’ significant terminal acquisitions since the beginning of 2005 included the following:

·

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

·

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

·

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

·

the Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, acquired in August 2005;

·

a terminal-related repair shop located in Jefferson County, Texas, acquired in September 2005;

·

three terminal operations acquired separately in April 2006: terminal equipment and infrastructure located on the Houston Ship Channel, a rail terminal located at the Port of Houston, and a rail ethanol terminal located in Carson, California; and

·

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.

Kinder Morgan Energy Partners has invested approximately $305.5 million in cash and $49.6 million in common units to acquire these terminal assets and combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues and expenses from terminal acquisitions were attributable to the inclusion of the Texas petroleum coke terminals and repair shop assets, which Kinder Morgan Energy Partners acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an aggregate consideration of approximately $247.2 million. The primary assets acquired included facilities and railway equipment located at the Port of Houston, the Port of Beaumont and the TGS Deepwater terminal located on the Houston Ship Channel. Combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $16.8 million, revenues of $31.0 million and operating expenses of $14.2 million, respectively, in 2006.

For 2005, Kinder Morgan Energy Partners benefited significantly from the incremental contributions attributable to the bulk and liquids terminal businesses acquired since the end of the third quarter of 2004. In addition to the 2005 acquisitions referred to above, these acquisitions included:

·

the river terminals and rail transloading facilities owned and operated by Kinder Morgan River Terminals LLC and its consolidated subsidiaries, acquired effective October 6, 2004; and

·

the Kinder Morgan Fairless Hills terminal located along the Delaware River in Bucks County, Pennsylvania, acquired effective December 1, 2004.



95



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




Combined, terminal operations acquired since the end of the third quarter of 2004 accounted for incremental amounts of earnings before depreciation, depletion and amortization of $45.5 million, revenues of $113.8 million and operating expenses of $65.0 million, respectively, in 2005. All of the incremental amounts listed above for both 2006 and 2005, represent the earnings, revenues and expenses from the acquired terminals’ operations during the additional months of ownership in 2006, and 2005, respectively, and do not include increases or decreases during the same months Kinder Morgan Energy Partners owned the assets in 2005 and 2004, respectively. For more information in regard to Kinder Morgan Energy Partners’ terminal acquisitions, see Note 4 of the accompanying Notes to Consolidated Financial statements.

Terminal Operations Owned During Both Comparable Years

For all other terminal operations (those owned during the same months of both comparable years), earnings before depreciation, depletion and amortization increased $60.0 million (19%) in 2006 compared to 2005, and decreased $12.6 million (4%) in 2005 compared to 2004; however, as described above, the net effect of the property casualty gain, hurricane repair expenses (net of income tax), and environmental liability adjustments resulted in a $14.8 million increase in earnings before depreciation, depletion and amortization in 2006 relative to 2005, and a $22.1 million decrease in 2005 relative to 2004. The remaining change in the earnings before depreciation, depletion and amortization expenses from terminal operations owned during both years consisted of a $45.2 million (14%) increase in 2006 compared to 2005, and a $9.5 million (4%) increase in 2005 compared to 2004. These respective year-to-year increases in earnings primarily consisted of the following:

·

increases of $17.4 million (23%) and $13.7 million (22%), respectively, from the Gulf Coast region. This region includes the operations of the two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas. The two terminals serve as a distribution hub for Houston’s crude oil refineries, and since the end of 2004, have contributed incremental earnings attributable to internal growth complemented by the completion of expansion projects undertaken to increase leaseable liquids capacity.

The year-over-year increase in earnings in 2006 versus 2005 was primarily revenue related, driven by increases from new and incremental customer agreements, additional liquids tank capacity from capital expansions at the Pasadena terminal since the end of 2005, higher truck loading rack service fees, higher ethanol throughput, and incremental revenues from customer deficiency charges.

Since the end of 2004, Kinder Morgan Energy Partners has obtained additional customer contracts, extended existing customer contracts and remarketed expiring contracted capacity at competitive rates. For the Gulf Coast and other liquids terminals, the existing contracts generally mature at various times and in varying amounts of throughput capacity, therefore, we continue to manage the recontracting process in order to limit the risk of significant impacts on Kinder Morgan Energy Partners’ revenues. The increase in earnings in 2005 versus 2004 was also largely due to higher revenues, driven by higher sales of petroleum transmix, new customer agreements, and escalations in annual contract provisions;

·

an increase of $9.4 million (29%) and a decrease of $3.3 million (10%), respectively, from the Mid-Atlantic region. The 2006 increase was driven by a $5.7 million increase from the Shipyard River terminal, located in Charleston, South Carolina; a $2.6 million increase from the Fairless Hills, Pennsylvania bulk terminal; and a $1.2 million increase from the North Charleston, South Carolina liquids terminal. The increase from Shipyard reflects higher revenues from liquids warehousing and coal and cement handling, the increase from Fairless Hills was due to higher volumes of steel imports and heavier shipping activity on the Delaware River, and the increase from North Charleston was due to higher revenues, associated with additional liquids tank leasing and a utilization capacity rate that approached 100% (full capacity).

The decrease in earnings in 2005 compared to 2004 included a $2.1 million decrease in earnings from the Pier IX bulk terminal, located in Newport News, Virginia, and a $2.0 million decrease in earnings from the Chesapeake Bay facility, located in Sparrows Point, Maryland. The decrease from Pier IX was primarily due to higher operating expenses in 2005 compared to 2004, due to incremental operating expenses associated with a new synfuel maintenance program and higher demurrage expenses associated with increased cement imports. The decrease from the Chesapeake terminal was mainly due to higher operating expenses associated with higher movements of petroleum coke;

·

an increase of $4.6 million (19%) and a decrease of $0.8 million, respectively, from terminals included in the Texas Petcoke region. The increase in 2006 compared to 2005 was primarily revenue driven, resulting from a year-over-year increase in petroleum coke handling volumes. The decrease in 2005 compared to 2004 was related to incremental overhead expenses allocated to the Texas Petcoke region, which was newly formed in April 2005;



96



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




·

an increase of $4.5 million (16%) and a decrease of $7.2 million (21%), respectively, from terminals included in the Lower Mississippi River (Louisiana) region. The increase in 2006 compared to 2005 was primarily due to incremental earnings from the Amory and DeLisle Mississippi bulk terminals, and from higher earnings from the Kinder Morgan St. Gabriel, Louisiana terminal. The Amory terminal began operations in July 2005. The higher earnings from the DeLisle terminal, which was negatively impacted by hurricane damage in 2005, was primarily due to higher bulk transfer revenues in 2006. The increase from the St. Gabriel terminal was primarily due to a $1.8 million income item, recognized in 2006, related to a favorable settlement associated with the purchase of the terminal in September 2002.

The overall decrease in earnings from the Louisiana region terminals in 2005 compared to 2004 was largely related to the negative effects of the two Gulf Coast hurricanes in 2005, resulting in an overall general loss of business.  In addition to property damage incurred, throughput at the facilities impacted by the storms decreased in 2005 compared to 2004 largely due to post-hurricane production issues at a number of Gulf Coast refineries. In 2005, the Terminals – KMP segment realized essentially all of the losses related to both hurricanes, and in total, the segment recognized $2.6 million in expense in 2005 in order to meet its insurance deductible for Hurricane Katrina. Kinder Morgan Energy Partners also recognized another $0.8 million to repair damaged facilities following Hurricane Rita, but estimates of lost business at the terminal sites are difficult because of insurance complexities and the extended recovery time involved;

·

an increase of $3.7 million (8%) and a decrease of $1.0 million (2%), respectively, from terminals included in the Northeast region. The increase in 2006 compared to 2005 was primarily due to higher earnings from the liquids terminals located in Carteret, New Jersey and Staten Island, New York. The increase was largely due to higher revenues from new and renegotiated customer contracts at Carteret, additional tankage available for lease at the Kinder Morgan Staten Island terminal, and an overall increase in petroleum imports to New York Harbor, resulting in an 8% increase in total liquids throughput at Carteret and higher distillate volumes at the Staten Island terminal.

The decrease in 2005 compared to 2004 was driven by lower earnings from the dry-bulk services at the Port Newark, New Jersey facility. The decrease was largely due to lower salt tonnage, shipping activity, and stevedoring services, all primarily due to warmer winter weather in 2005; and

·

increases of $2.2 million (4%) and $4.4 million (10%), respectively, from terminals in the Midwest region. The year-over-year increase in earnings in 2006 was mainly attributable to higher earnings from the combined operations of the Argo and Chicago, Illinois liquids terminals, and from the Cora, Illinois coal terminal. The increase from the liquids terminals was due to higher revenues from increased ethanol throughput and incremental liquids storage and handling business. The year-to-year increase in earnings at Cora was due to higher revenues resulting from an almost 24% increase in coal transfer volumes.

The overall increase in 2005 compared to 2004 included higher earnings from the Dakota bulk terminal, located along the Mississippi River near St. Paul, Minnesota; the Argo, Illinois liquids terminal, situated along the Chicago sanitary and ship channel; and the Milwaukee, Wisconsin bulk commodity terminal. The increase in earnings from Dakota was primarily due to higher revenues generated by a cement unloading and storage facility, which began operations in late 2004. The increase from the Argo terminal was mainly due to new customer contracts and higher ethanol handling revenues. The increase from the Milwaukee bulk terminal was mainly due to an increase in coal handling revenues related to higher coal truckage within the State of Wisconsin.

Segment Details

Segment revenues from terminal operations owned during identical periods of both 2006 and 2005 increased $96.7 million (14%) in 2006, when compared to the prior year. The overall increase was primarily due to the following:

·

a $24.1 million (29%) increase from the Mid-Atlantic region, due primarily to higher revenues of $11.7 million from Fairless Hills, $9.7 million from Shipyard River, and $1.6 million from the North Charleston terminals, all discussed above. Also, the Philadelphia, Pennsylvania liquids terminal reported a $2.5 million increase in revenues in 2006 versus 2005 largely due to an increase in fuel grade ethanol volumes, annual rate escalations on certain customer contracts, and a 2006 liquids capacity utilization rate of approximately 97%;

·

a $19.6 million (19%) increase from the Gulf Coast liquids facilities, due primarily to higher revenues from Pasadena and Galena Park, as discussed above;

·

a $19.1 million (43%) increase from the Texas Petcoke terminal region, due primarily to higher petroleum coke transfer volumes;



97



Item 7.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations. (continued)

KMI Form 10-K

    




·

a $13.4 million (92%) increase from engineering and terminal design services, due to both incremental revenues from new clients, additional project phase revenues, and increased revenues from material sales;

·

a $5.5 million (5%) increase from terminals included in the Midwest region, due largely to the increased liquids throughput, storage and ethanol activities from the two Chicago liquids terminals and to the increased coal volumes from the Cora coal terminal, both described above. The overall increase in revenues was also due to higher marine oil fuel and asphalt sales from the Dravosburg, Pennsylvania bulk terminal;

·

a $5.1 million (16%) increase from the Ferro alloys region, largely due to increased ores and metals handling at the Chicago and Industry, Pennsylvania terminals; and

·

a $4.6 million (5%) increase from the Northeast terminals, largely due to the revenue increases at the Carteret and Kinder Morgan Staten Island terminals, as discussed above.

For all bulk terminal facilities combined, total transloaded bulk tonnage volumes increased over 4.5% in 2006, when compared to 2005. The overall increase in bulk tonnage volumes included a 10% increase in coal transfer volumes and a 13% increase in ores/metals transload volumes. Kinder Morgan Energy Partners also completed, in 2006, capital expansion and betterment projects at certain of its liquids terminal facilities that included the construction of additional petroleum products storage tanks. The construction, when combined with increases from external acquisitions, increased Kinder Morgan Energy Partners’ liquids storage capacity by approximately 1.1 million barrels (2.6%) in 2006. At the same time, Kinder Morgan Energy Partners increased its liquids utilization capacity rate by 1%, compared to the prior year. The liquids terminals utilization rate is the ratio of actual leased capacity to estimated potential capacity. Potential capacity is generally derived from measures of total capacity, taking into account periodic changes to terminal facilities due to additions, disposals, obsolescence, or other factors.

Segment revenues for all terminals owned during identical periods of both 2005 and 2004 increased $43.6 million (8%) in 2005, when compared to the prior year. The increase was primarily due to the following:

·

a $16.7 million (19%) increase from the Pasadena and Galena Park Gulf Coast liquids terminals, due primarily to higher petroleum transmix sales and to additional customer contracts and tankage capacity;

·

a $12.3 million (14%) increase from the Midwest region, due primarily to higher cement handling revenues at the Dakota terminal, increased tonnage at the Milwaukee terminal, and higher marine fuel sales at the Dravosburg, Pennsylvania terminal;

·

a $6.8 million (11%) increase from the Mid-Atlantic region, due primarily to higher coal volumes and higher dockage revenues at the Shipyard River terminal, higher cement, iron ore, and dockage revenues at the Pier IX bulk terminal, and incremental revenues from the North Charleston liquids/bulk terminal, located just north of the Shipyard facility and acquired effective April 30, 2004;

·

a $4.0 million (38%) increase from engineering and terminal design services, due to increased fee revenues discussed above;

·

a $3.9 million (9%) increase from the Southeast region, due primarily to both higher fertilizer and ammonia volumes and higher stevedoring services at terminal operations located