Kinder Morgan Management, LLC Form 10-K

KMR 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 1-16459

Kinder Morgan Management, LLC

(Exact name of registrant as specified in its charter)


Delaware		76-0669886
(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
Shares Representing Limited Liability Company Interests		New York Stock Exchange

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

None

(Title of class)

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

Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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. þ

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

KMR Form 10-K

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $2,177,434,973 as of June 30, 2006.

The number of shares outstanding for each of the registrant’s classes of common equity, as of January 31, 2007 was approximately two voting shares and 62,301,674 listed shares.

KMR Form 10-K

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

CONTENTS


		Page Number
	PART I

Items 1 and 2:	Business and Properties	4-5
Item 1A:	Risk Factors	6-8
Item 1B:	Unresolved Staff Comments	8
Item 3:	Legal Proceedings	8
Item 4:	Submission of Matters to a Vote of Security Holders	8

	PART II

Item 5:	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
	of Equity Securities	9
Item 6:	Selected Financial Data	10
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10-14
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	14
Item 8:	Financial Statements and Supplementary Data	15-26
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	26
Item 9A:	Controls and Procedures	26
	Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures	26
	Management Report on Internal Control over Financial Reporting	26
	Changes in Internal Control over Financial Reporting	27
Item 9B:	Other Information	27

	PART III

Item 10:	Directors, Executive Officers and Corporate Governance	28-30
Item 11:	Executive Compensation	30-44
Item 12:	Security Ownership of Certain Beneficial Owners and Management
	Related Stockholder Matters	45-47
Item 13:	Certain Relationships and Related Transactions, and Director Independence	47-51
Item 14:	Principal Accounting Fees and Services	51-52

	PART IV

Item 15:	Exhibits and Financial Statement Schedules	53-54

Signatures		55


Kinder Morgan Energy Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 2006		Annex A

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

KMR 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 Management, LLC and its consolidated subsidiary. Our shares representing limited liability company interests are traded on the New York Stock Exchange under the symbol “KMR”. Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000.

We are a publicly traded Delaware limited liability company that was formed on February 14, 2001. We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Our success is dependent upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. Therefore, we have attached hereto as Annex A Kinder Morgan Energy Partners, L.P.’s 2006 Annual Report on Form 10-K. Pursuant to the delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., Kinder Morgan Energy Partners, L.P.’s operating partnerships and us:

Kinder Morgan G.P., Inc., as general partner of Kinder Morgan Energy Partners, L.P., delegated to us, to the fullest extent permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, and we assumed, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.’s operating partnerships; and

We have agreed that we will not take any of the following actions without the approval of Kinder Morgan G.P., Inc.:

–

amend or propose an amendment to the Kinder Morgan Energy Partners, L.P. partnership agreement,

–

change the amount of the distribution made on the Kinder Morgan Energy Partners, L.P. common units,

–

allow a merger or consolidation involving Kinder Morgan Energy Partners, L.P.,

–

allow a sale or exchange of all or substantially all of the assets of Kinder Morgan Energy Partners, L.P.,

–

dissolve or liquidate Kinder Morgan Energy Partners, L.P.,

–

take any action requiring unitholder approval,

–

call any meetings of the Kinder Morgan Energy Partners, L.P. common unitholders,

–

take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., must or should receive a special approval of the conflicts and audit committee of Kinder Morgan G.P., Inc.,

–

take any action that, under the terms of the partnership agreement of Kinder Morgan Energy Partners, L.P., cannot be taken by the general partner without the approval of all outstanding units,

–

settle or compromise any claim or action directly against or otherwise relating to indemnification of our or the general partner’s (and respective affiliates) officers, directors, managers or members or relating to our structure or securities,

–

settle or compromise any claim or action relating to the i-units, which are a separate class of Kinder Morgan Energy Partners, L.P.’s limited partnership interests, our shares or any offering of our shares,

–

settle or compromise any claim or action involving tax matters,

–

allow Kinder Morgan Energy Partners, L.P. to incur indebtedness if the aggregate amount of its indebtedness then exceeds 50% of the market value of the then outstanding units of Kinder Morgan Energy Partners, L.P., or

–

allow Kinder Morgan Energy Partners, L.P. to issue units in one transaction, or in a series of related transactions, having a market value in excess of 20% of the market value of then outstanding units of Kinder Morgan Energy Partners, L.P.

Kinder Morgan G.P., Inc.:

–

is not relieved of any responsibilities or obligations to Kinder Morgan Energy Partners, L.P. or its unitholders as a result of such delegation,

–

owns, or one of its affiliates owns, all of our voting shares, and


Items 1 and 2. Business and Properties. (continued)	KMR Form 10-K

–

will not withdraw as general partner of Kinder Morgan Energy Partners, L.P. or transfer to a non-affiliate all of its interest as general partner, unless approved by both the holders of a majority of each of the i-units and the holders of a majority of all units voting as a single class, excluding common units and Class B units held by Kinder Morgan G.P., Inc. and its affiliates and excluding the number of i-units corresponding to the number of our shares owned by Kinder Morgan G.P., Inc. and its affiliates.

Kinder Morgan Energy Partners, L.P. has agreed to:

–

recognize the delegation of rights and powers to us,

–

indemnify and protect us and our officers and directors to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner, and

–

reimburse our expenses to the same extent as it does with respect to Kinder Morgan G.P., Inc. as general partner.

The delegation of control agreement will continue in effect until either Kinder Morgan G.P., Inc. has withdrawn or been removed as the general partner of Kinder Morgan Energy Partners, L.P. or all of our shares are owned by Kinder Morgan, Inc. and its affiliates. The partnership agreement of Kinder Morgan Energy Partners, L.P. recognizes the delegation of control agreement. The delegation of control agreement also applies to the operating partnerships of Kinder Morgan Energy Partners, L.P. and their partnership agreements.

Kinder Morgan G.P., Inc. remains the sole general partner of Kinder Morgan Energy Partners, L.P. and all of its operating partnerships. Kinder Morgan G.P., Inc. retains all of its general partner interests and shares in the profits, losses and distributions from all of these partnerships.

The withdrawal or removal of Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners, L.P. will simultaneously result in the termination of our power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. Similarly, if Kinder Morgan G.P., Inc.’s power and authority as general partner are modified in the partnership agreement of Kinder Morgan Energy Partners, L.P., then the power and authority delegated to us will be modified on the same basis. The delegation of control agreement can be amended by all parties to the agreement, but on any amendment that would reduce the time for any notice to which owners of our shares are entitled or that would have a material adverse effect on our shares, as determined by our board of directors in its discretion, the approval of the owners of a majority of the shares, excluding shares owned by Kinder Morgan, Inc. and its affiliates, is required.

Through our ownership of i-units, we are a limited partner in Kinder Morgan Energy Partners, L.P. We do not expect to have any cash flow attributable to our ownership of the i-units, but we expect that we will receive quarterly distributions of additional i-units from Kinder Morgan Energy Partners, L.P. The number of additional i-units we receive will be based on the amount of cash to be distributed by Kinder Morgan Energy Partners, L.P. to an owner of one of its common units. The amount of cash distributed by Kinder Morgan Energy Partners, L.P. to its owners of common units is dependent on the operations of Kinder Morgan Energy Partners, L.P. and its operating limited partnerships and their subsidiaries and investees, and will be determined in accordance with its partnership agreement.

We have elected to be treated as a corporation for federal income tax purposes. Because we are treated as a corporation for federal income tax purposes, an owner of our shares will not report on its federal income tax return any of our items of income, gain, loss and deduction relating to an investment in us.

We are subject to federal income tax on our taxable income; however, the i-units owned by us generally are not entitled to allocations of income, gain, loss or deduction of Kinder Morgan Energy Partners, L.P. until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. Therefore, we do not anticipate that we will have material amounts of taxable income resulting from our ownership of the i-units unless we enter into a sale or exchange of the i-units or Kinder Morgan Energy Partners, L.P. is liquidated.

We have no properties. Our assets consist of a small amount of working capital and the i-units that we own.

We have no employees. For more information, see Note 4 of the accompanying Notes to Consolidated Financial Statements and Kinder Morgan Energy Partners, L.P.’s report on Form 10-K for the year ended December 31, 2006.

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


Items 1 and 2. Business and Properties. (continued)	KMR Form 10-K

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.

Because our only assets are the i-units issued by Kinder Morgan Energy Partners, L.P., our success is dependent solely upon our operation and management of Kinder Morgan Energy Partners, L.P. and its resulting performance. We are a limited partner in Kinder Morgan Energy Partners, L.P. In the event that Kinder Morgan Energy Partners, L.P. decreases its cash distributions to its common unitholders, distributions of i-units on the i-units that we own will decrease correspondingly, and distributions of additional shares to owners of our shares will decrease as well. The risk factors that affect Kinder Morgan Energy Partners, L.P. also affect us; see “Risk Factors” for Kinder Morgan Energy Partners, L.P. included in Exhibit 99.1.

The value of the quarterly distribution of an additional fractional share may be less than the cash distribution on a common unit of Kinder Morgan Energy Partners, L.P. The fraction of a Kinder Morgan Management, LLC share to be issued per share outstanding with each quarterly distribution is based on the average closing price of the shares for the ten consecutive trading days preceding the ex-dividend date for our shares. Because the market price of our shares may vary substantially over time, the market value of our shares on the date a shareholder receives a distribution of additional shares may vary substantially from the cash the shareholder would have received had the shareholder owned common units instead of our shares.

Kinder Morgan Energy Partners, L.P. could be treated as a corporation for United States federal income tax purposes. The treatment of Kinder Morgan Energy Partners, L.P. as a corporation would substantially reduce the cash distributions on the common units and the value of i-units that Kinder Morgan Energy Partners, L.P. will distribute quarterly to us and the value of our shares that we will distribute quarterly to our shareholders. The anticipated benefit of an investment in our shares depends largely on the treatment of Kinder Morgan Energy Partners, L.P. as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. 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, L.P. Current law requires Kinder Morgan Energy Partners, L.P. to derive at least 90% of its annual gross income from specific activities to continue to be treated as a partnership for United States federal income tax purposes. Kinder Morgan Energy Partners, L.P. 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, L.P. to be treated as a corporation for United States federal income tax purposes without regard to its sources of income or otherwise subject Kinder Morgan Energy Partners, L.P. to entity-level taxation.

If Kinder Morgan Energy Partners, L.P. were to be treated as a corporation for United States federal income tax purposes, it would pay United States federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Distributions to us of additional i-units would generally be taxed as a corporate distribution. Because a tax would be imposed upon Kinder Morgan Energy Partners, L.P. as a corporation, the cash available for distribution to common unitholders would be substantially reduced, which would reduce the values of i-units distributed quarterly to us and our shares distributed quarterly to our shareholders. Treatment of Kinder Morgan Energy Partners, L.P. as a corporation would cause a substantial reduction in the value of our shares.

As an owner of i-units, we may not receive value equivalent to the common unit value for our i-unit interest in Kinder Morgan Energy Partners, L.P. if Kinder Morgan Energy Partners, L.P. is liquidated. As a result, a shareholder may receive less per share in our liquidation than is received by an owner of a common unit in a liquidation of Kinder Morgan Energy Partners, L.P. If Kinder Morgan Energy Partners, L.P. is liquidated and Kinder Morgan, Inc. does not satisfy its obligation to purchase your shares, which is triggered by a liquidation, then the value of your shares will depend on the after-tax amount of the liquidating distribution received by us as the owner of i-units. The terms of the i-units provide that no allocations of income, gain, loss or deduction will be made in respect of the i-units until such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. If there is a liquidation of Kinder Morgan Energy Partners, L.P., it is intended that we will receive allocations of income and gain in an amount necessary for the capital account attributable to each i-unit to be equal to that of a common unit. As a result, we will likely realize taxable income upon the liquidation of Kinder Morgan Energy Partners, L.P. However, there may not be sufficient amounts of income and gain to cause the capital account attributable to each i-unit to be equal to that of a common unit. If they are not equal, we, and therefore our shareholders, will receive less value than would be received by an owner of common units.

Further, the tax indemnity provided to us by Kinder Morgan, Inc. only indemnifies us for our tax liabilities to the extent we have not received sufficient cash in the transaction generating the tax liability to pay the associated tax. Prior to any liquidation of Kinder Morgan Energy Partners, L.P., we do not expect to receive cash in a taxable transaction. If a liquidation of Kinder Morgan Energy Partners, L.P. occurs, however, we likely would receive cash which would need to be used at least


Items 1 and 2. Business and Properties. (continued)	KMR Form 10-K

in part to pay taxes. As a result, our residual value and the value of our shares likely will be less than the value of the common units upon the liquidation of Kinder Morgan Energy Partners, L.P.

Our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships could result in our being liable for obligations to third parties who transact business with Kinder Morgan Energy Partners, L.P. and its operating partnerships and to whom we held ourselves out as a general partner. We could also be responsible for environmental costs and liabilities associated with Kinder Morgan Energy Partners, L.P.’s assets in the event that it is not able to perform all of its obligations under environmental laws. Kinder Morgan Energy Partners, L.P. may not be able to reimburse or indemnify us as a result of its insolvency or bankruptcy. The primary adverse impact of that insolvency or bankruptcy on us would be the decline in or elimination of the value of our i-units, which are our only significant assets. Assuming under these circumstances that we have some residual value in our i-units, a direct claim by creditors of Kinder Morgan Energy Partners, L.P. against us could further reduce our net asset value and cause us also to declare bankruptcy. Another risk with respect to third party claims will occur, however, under the circumstances when Kinder Morgan Energy Partners, L.P. is financially able to pay us, but for some other reason does not reimburse or indemnify us. For example, to the extent that Kinder Morgan Energy Partners, L.P. fails to satisfy any environmental liabilities for which it is responsible, we could be held liable under environmental laws. For additional information, see the following risk factor.

If we are not fully indemnified by Kinder Morgan Energy Partners, L.P. for all the liabilities we incur in performing our obligations under the delegation of control agreement, we could face material difficulties in paying those liabilities, and the net value of our assets could be adversely affected. Under the delegation of control agreement, we have been delegated management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships. There are circumstances under which we may not be indemnified by Kinder Morgan Energy Partners, L.P. or Kinder Morgan G.P., Inc. for liabilities we incur in managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. These circumstances include:

if we act in bad faith; and

if we breach laws like the federal securities laws, where indemnification may not be allowed.

If in the future we cease to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., we may be deemed to be an investment company for purposes of the Investment Company Act of 1940. In that event, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with our affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add directors who are independent of us or our affiliates.

The interests of Kinder Morgan, Inc. may differ from our interests, the interests of our shareholders and the interests of unitholders of Kinder Morgan Energy Partners, L.P. Kinder Morgan, Inc. owns all of the stock of the general partner of Kinder Morgan Energy Partners, L.P. and elects all of its directors. The general partner of Kinder Morgan Energy Partners, L.P. owns all of our voting shares and elects all of our directors. Furthermore, some of our directors and officers are also directors and officers of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P. and have fiduciary duties to manage the businesses of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. in a manner that may not be in the best interest of our shareholders. Kinder Morgan, Inc. has a number of interests that differ from the interests of our shareholders and the interests of the unitholders. As a result, there is a risk that important business decisions will not be made in the best interest of our shareholders.

Our limited liability company agreement restricts or eliminates a number of the fiduciary duties that would otherwise be owed by our board of directors to our shareholders, and the partnership agreement of Kinder Morgan Energy Partners, L.P. restricts or eliminates a number of the fiduciary duties that would otherwise be owed by the general partner to the unitholders. Modifications of state law standards of fiduciary duties may significantly limit the ability of our shareholders and the unitholders to successfully challenge the actions of our board of directors and the general partner, respectively, in the event of a breach of their fiduciary duties. These state law standards include the duties of care and loyalty. The duty of loyalty, in the absence of a provision in the limited liability company agreement or the limited partnership agreement to the contrary, would generally prohibit our board of directors or the general partner from taking any action or engaging in any transaction as to which it has a conflict of interest. Our limited liability company agreement and the limited partnership agreement of Kinder Morgan Energy Partners, L.P. contain provisions that prohibit our shareholders and the limited partners, respectively, from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law. For example, the limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides that the general partner may take into account the interests of parties other than Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest. Further, it provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general


Items 1 and 2. Business and Properties. (continued)	KMR Form 10-K

partner will not be a breach of any duty. The provisions relating to the general partner apply equally to us as its delegate. Our limited liability company agreement provides that none of our directors or officers will be liable to us or any other person for any acts or omissions if they acted in good faith.

Item 1B.

Unresolved Staff Comments.

None.

Item 3.

Legal Proceedings.

We are not a party to any litigation.

Item 4.

Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of our shareholders during the fourth quarter of 2006.

KMR Form 10-K

PART II

Item 5.

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

Our shares are listed for trading on the New York Stock Exchange under the symbol “KMR.” The per share high and low sale prices of our shares, as reported on the New York Stock Exchange, by quarter for the last two years are provided below.


	Market Price Per Share
	2006		2005
	Low	High	Low	High
Quarter Ended:
March 31	$41.21	$47.25	$39.33	$43.93
June 30	$40.09	$45.06	$40.93	$46.47
September 30	$41.35	$43.60	$46.01	$50.05
December 31	$41.26	$47.05	$44.50	$50.06

There were approximately 29,000 holders of our listed shares as of February 1, 2007, which includes individual participants in security position listings.

Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for the ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.


	Share Distributions
	Shares Distributed Per Outstanding Share		Equivalent Distribution Value Per Share¹				Total Number of Additional Shares Distributed
Quarter Ended:	2006	2005	2006		2005		2006	2005
March 31	0.018566	0.017482	$	0.81	$	0.76	1,093,826	963,495
June 30	0.018860	0.016210	$	0.81	$	0.78	1,131,777	909,009
September 30	0.018981	0.016360	$	0.81	$	0.79	1,160,520	932,292
December 31	0.016919	0.017217	$	0.83	$	0.80	1,054,082	997,180

___________

This is the cash distribution paid or payable to each common unit of Kinder Morgan Energy Partners, L.P. for the quarter indicated and is used to calculate our distribution of shares as discussed above. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P.

There were no sales of unregistered equity securities during the periods covered by this report. We did not repurchase any shares during the fourth quarter of 2006.

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

KMR Form 10-K

Item 6.

Selected Financial Data.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY


	Year Ended December 31,
	2006		2005		2004		2003		2002
	(In thousands except per share amounts)
Equity in Earnings of Kinder Morgan Energy Partners, L.P.	$	123,155	$	88,448	$	113,482	$	94,775	$	72,199
Provision for Income Taxes		44,165		32,124		38,360		36,014		26,865
Net Income	$	78,990	$	56,324	$	75,122	$	58,761	$	45,334
Earnings Per Share, Basic and Diluted	$	1.31	$	1.00	$	1.47	$	1.24	$	1.23
Number of Shares Used in Computing Basic and Diluted Earnings Per Share		60,074		56,090		51,181		47,372		36,790
Equivalent Distribution Value Per Share¹	$	3.260	$	3.130	$	2.870	$	2.630	$	2.435
Total Number of Additional Shares Distributed		4,440		3,802		3,678		3,262		2,944
Total Assets at End of Period	$	1,699,971	$	1,583,661	$	1,639,348	$	1,506,286	$	1,439,190

This is the amount of cash distributions payable to each common unit of Kinder Morgan Energy Partners, L.P. for each period shown. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares. Because of this calculation, the market value of the shares distributed on the date of distribution may be less or more than the cash distribution per common unit of Kinder Morgan Energy Partners, L.P.

Item 7.

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

General

We are a publicly traded Delaware limited liability company, formed on February 14, 2001, that has elected to be treated as a corporation for federal income tax purposes. Our voting shares are owned by Kinder Morgan, G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc. and the general partner of Kinder Morgan Energy Partners, L.P.

Kinder Morgan, Inc. is one of the largest energy transportation, storage and distribution companies in North America, operating, either for itself or on behalf of Kinder Morgan Energy Partners, L.P., or owning an interest in approximately 43,000 miles of pipelines that transport primarily natural gas, crude oil, petroleum products and carbon dioxide; more than 155 terminals that store, transfer and handle products like gasoline and coal; and providing natural gas distribution service to over 1.1 million customers. On August 28, 2006, Kinder Morgan, Inc. entered into a definitive merger agreement under which investors led by Richard D. Kinder, Kinder Morgan, Inc.’s Chairman and Chief Executive Officer, would acquire all of its outstanding common stock for $107.50 per share in cash. Kinder Morgan, Inc.’s board of directors, on the unanimous recommendation of a special committee composed entirely of independent directors, approved the agreement and recommended that Kinder Morgan, Inc.’s stockholders approve the merger. Kinder Morgan, Inc.’s stockholders voted to approve the proposed merger agreement at a special meeting on December 19, 2006. 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.

Kinder Morgan Energy Partners, L.P. is 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. Kinder Morgan Energy Partners, L.P. owns and/or operates approximately 26,000 miles of pipelines and approximately 150 terminals. Kinder Morgan Energy Partners, L.P.’s pipelines transport more than two million barrels per day of gasoline and other petroleum products and up to seven billion cubic feet per day of natural gas. Kinder Morgan Energy Partners, L.P.’s 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. Kinder Morgan Energy Partners, L.P. is also the leading independent provider of carbon dioxide for enhanced oil recovery projects in the United States.

We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. Our success is dependent upon our operation and management of Kinder Morgan Energy

Item 7.

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

KMR Form 10-K

Partners, L.P. and its resulting performance. Therefore, we have attached hereto as Annex A Kinder Morgan Energy Partners, L.P.’s 2006 Annual Report on Form 10-K. The following discussion should be read in conjunction with the accompanying financial statements and related notes.

Business

Kinder Morgan G.P., Inc. has delegated to us, to the fullest extent permitted under Delaware law and Kinder Morgan Energy Partners, L.P.’s limited partnership agreement, all of its rights and powers to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P. subject to Kinder Morgan G.P., Inc.’s right to approve specified actions.

Results of Operations

Our results of operations consist of the offsetting expenses and revenues associated with our managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and our equity in the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. At December 31, 2006, through our ownership of i-units, we owned approximately 27.0% of all of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner interests. We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P. and, therefore, we record earnings equal to approximately 27.0% of Kinder Morgan Energy Partners, L.P.’s limited partners’ net income. Our percentage ownership in Kinder Morgan Energy Partners, L.P. will change over time upon the distribution of additional i-units to us or upon issuances of additional common units or other equity securities by Kinder Morgan Energy Partners, L.P.

For the years ended December 31, 2006, 2005 and 2004, Kinder Morgan Energy Partners, L.P. reported limited partners’ net income of $459.2 million, $334.9 million and $436.5 million, respectively. Our net income for the corresponding periods was $79.0 million, $56.3 million and $75.1 million, respectively. The reported segment earnings contribution by business segment for Kinder Morgan Energy Partners, L.P. is set forth below. This information should be read in conjunction with Kinder Morgan Energy Partners, L.P.’s 2006 Annual Report on Form 10-K, which is attached hereto as Annex A.

Kinder Morgan Energy Partners, L.P.


	Year Ended December 31,
	2006			2005			2004
	(In thousands)
Segment Earnings Contribution:
Product Pipelines	$	404,900		$	287,503		$	370,321
Natural Gas Pipelines		509,140			438,386			364,872
CO₂		295,231			318,980			234,258
Terminals		333,592			255,529			238,848
Total Segment Earnings		1,542,863			1,300,398			1,208,299
Interest and Corporate Administrative Expenses¹		(570,720	)		(488,171	)		(376,721	)
Net Income	$	972,143		$	812,227		$	831,578

Includes interest and debt expense, general and administrative expenses, minority interest expense and other insignificant items.

Our earnings, as reported in the accompanying Consolidated Statements of Income, represent equity in earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units that we own, reduced by a deferred income tax provision. The deferred income tax provision is calculated based on the book/tax basis difference created by our recognition, under accounting principles generally accepted in the United States of America, of our share of the earnings of Kinder Morgan Energy Partners, L.P. Our earnings per share (both basic and diluted) is our net income divided by our weighted-average number of outstanding shares during the periods presented. There are no securities outstanding that may be converted into or exercised for shares.

Income Taxes

We are a limited liability company that has elected to be treated as a corporation for federal income tax purposes. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of our assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Currently, our only such temporary difference results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P.

The income tax provision increased from $32.1 million in 2005 to $44.2 million in 2006, an increase of $12.1 million (37.7%). The net increase of $12.1 million principally results from an increase in pre-tax income of $34.7 million.

Item 7.

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

KMR Form 10-K

The income tax provision decreased from $38.4 million in 2004 to $32.1 million in 2005, a decrease of $6.3 million (16.4%) due principally to (i) the fact that the tax provision for 2004 includes a reduction of $2.9 million due to the impact of applying a lower effective tax rate on previously recorded net deferred tax liabilities and (ii) a decrease of $9.2 million due to a decrease in pre-tax income of $25.0 million.

The effective tax rate used in computing our income tax provision was 35.9% for 2006, 36.3% for 2005 and 33.8% for 2004. The effective tax rate for 2004 was reduced by 2.5%, due to a reduction in the state tax rate on our cumulative deferred tax liability.

We are a party to a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P., and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.

See Note 2E of the accompanying Notes to Consolidated Financial Statements for additional information on income taxes.

Liquidity and Capital Resources

Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our “shares.” Additional classes of interests may be approved by our board and holders of a majority of our shares, excluding shares held by Kinder Morgan, Inc. and its affiliates. Our only off-balance sheet arrangement is our equity investment in Kinder Morgan Energy Partners, L.P.

The number of our shares outstanding will at all times equal the number of i-units of Kinder Morgan Energy Partners, L.P. we own. Under the terms of our limited liability company agreement, except in connection with our liquidation, we do not pay distributions on our shares in cash but we make distributions on our shares in additional shares or fractions of shares. At the same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common units and i-units, we distribute on each of our shares that fraction of a share determined by dividing the amount of the cash distribution to be made by Kinder Morgan Energy Partners, L.P. on each common unit by the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.

On February 14, 2007, we paid a share distribution of 0.016919 shares per outstanding share (1,054,082 total shares) to shareholders of record as of January 31, 2007, based on the $0.83 per common unit distribution declared by Kinder Morgan Energy Partners, L.P. This distribution is paid in the form of additional shares or fractions thereof based on the average market price of a share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for our shares.

We expect that our expenditures associated with managing and controlling the business and affairs of Kinder Morgan Energy Partners, L.P. and the reimbursement for these expenditures received by us from Kinder Morgan Energy Partners, L.P. will continue to be equal. As stated above, the distributions we expect to receive on the i-units we own will be in the form of additional i-units. Therefore, we expect neither to generate nor to require significant amounts of cash in ongoing operations. We currently have no debt and have no plans to incur any debt. Any cash received from the sale of additional shares will immediately be used to purchase additional i-units. Accordingly, we do not anticipate any other sources or needs for additional liquidity.

Recent Accounting Pronouncements

Refer to Note 6 of the accompanying Consolidated Financial Statements for information regarding recent accounting pronouncements.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to pay dividends or make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of our operations and those of Kinder Morgan Energy Partners, L.P. may differ materially from those expressed in these forward-looking statements. Please see “Information Regarding Forward-Looking Statements” for Kinder Morgan Energy Partners, L.P. included in Exhibit 99.1. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:

Item 7.

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

KMR Form 10-K

price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in North America;

economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

changes in Kinder Morgan Energy Partners, L.P.’s tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;

Kinder Morgan Energy Partners, L.P.’s ability to acquire new businesses and assets and integrate those operations into its existing operations, as well as its ability to make expansions to its facilities;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners, L.P.’s terminals or pipelines;

Kinder Morgan Energy Partners, L.P.’s ability to successfully identify and close acquisitions and make cost-saving changes in operations;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use Kinder Morgan Energy Partners, L.P.’s services or provide services or products to Kinder Morgan Energy Partners, L.P.;

crude oil and natural gas production from exploration and production areas that Kinder Morgan Energy Partners, L.P. serves, including, among others, the Permian Basin area of West Texas;

changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies that may adversely affect Kinder Morgan Energy Partners, L.P.’s business or its ability to compete;

changes in accounting pronouncements that impact the measurement of Kinder Morgan Energy Partners, L.P.’s or our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

our ability to offer and sell equity securities and Kinder Morgan Energy Partners, L.P.’s ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of Kinder Morgan Energy Partners, L.P.’s business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of its facilities;

Kinder Morgan Energy Partners, L.P.’s indebtedness could make it vulnerable to general adverse economic and industry conditions, limit its ability to borrow additional funds and/or place it at competitive disadvantages compared to its competitors that have less debt or have other adverse consequences;

interruptions of electric power supply to Kinder Morgan Energy Partners, L.P.’s facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;

our and Kinder Morgan Energy Partners, L.P.’s ability to obtain insurance coverage without a significant level of self-retention of risk;

acts of nature, sabotage, terrorism or other similar acts causing damage greater than Kinder Morgan Energy Partners, L.P.’s insurance coverage limits;

capital markets conditions;

the political and economic stability of the oil producing nations of the world;

national, international, regional and local economic, competitive and regulatory conditions and developments;

the ability of Kinder Morgan Energy Partners, L.P. to achieve cost savings and revenue growth;

inflation;

interest rates;

the pace of deregulation of retail natural gas and electricity;

Item 7.

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

KMR Form 10-K

foreign exchange fluctuations;

the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products;

the extent of Kinder Morgan Energy Partners, L.P.’s success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

engineering and mechanical or technological difficulties that Kinder Morgan Energy Partners, L.P. may experience with operational equipment, in well completions and workovers, and in drilling new wells;

the uncertainty inherent in estimating future oil and natural gas production or reserves that Kinder Morgan Energy Partners, L.P. may experience;

the ability of Kinder Morgan Energy Partners, L.P. to complete expansion projects on time and on budget;

the timing and success of Kinder Morgan Energy Partners, L.P.’s business development efforts; and

unfavorable results of litigation involving Kinder Morgan Energy Partners, L.P. and the fruition of contingencies referred to in Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2006.

There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Other than as required by applicable law, we disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

The nature of our business and operations is such that no activities or transactions of the type requiring discussion under this item are conducted or entered into.

KMR Form 10-K

Item 8. Financial Statements and Supplementary Data.

INDEX


	Page

Report of Independent Registered Public Accounting Firm	16
Consolidated Statements of Income	17
Consolidated Statements of Comprehensive Income	17
Consolidated Balance Sheets	18
Consolidated Statements of Shareholders’ Equity	19
Consolidated Statements of Cash Flows	20
Notes to Consolidated Financial Statements	21-25
Selected Quarterly Financial Data (unaudited)	25
Supplemental Information on Oil and Gas Producing Activities (unaudited)	25-26


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan Management, LLC:

We have completed integrated audits of Kinder Morgan Management, LLC’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Management, LLC and its subsidiary (the “Company”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2007


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

CONSOLIDATED STATEMENTS OF INCOME
Kinder Morgan Management, LLC and Subsidiary


	Year Ended December 31,
	2006		2005		2004
	(In thousands)
Equity in Earnings of Kinder Morgan Energy Partners, L.P.	$	123,155	$	88,448	$	113,482
Provision for Income Taxes		44,165		32,124		38,360

Net Income	$	78,990	$	56,324	$	75,122

Earnings Per Share, Basic and Diluted	$	1.31	$	1.00	$	1.47

Number of Shares Used in Computing Basic and Diluted Earnings Per Share		60,074		56,090		51,181

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Year Ended December 31,
	2006			2005			2004
	(In thousands)
Net Income	$	78,990		$	56,324		$	75,122
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax Benefit of $15,882, $99,046 and $47,200, respectively)		(28,093	)		(173,660	)		(82,764	)
Reclassification of Change in Fair Value of Derivatives to Net Income (Net of Tax of $36,260, $40,162 and $18,366, respectively)		64,139			70,417			32,204
Change in Foreign Currency Translation Adjustment		108			(116	)		63
Total Other Comprehensive Income (Loss)		36,154			(103,359	)		(50,497	)

Comprehensive Income	$	115,144		$	(47,035	)	$	24,625

The accompanying notes are an integral part of these statements.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

CONSOLIDATED BALANCE SHEETS
Kinder Morgan Management, LLC and Subsidiary


	December 31,
	2006			2005
	(In thousands)
ASSETS

Current Assets:
Accounts Receivable – Related Party	$	14,674		$	22,230
Prepayments and Other		4,050			3,498
		18,724			25,728

Investment in Kinder Morgan Energy Partners, L.P.		1,681,247			1,557,933

Total Assets	$	1,699,971		$	1,583,661

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities:
Accounts Payable	$	1,231		$	2,648
Accrued Expenses and Other		17,417			23,004
		18,648			25,652

Deferred Income Taxes		106,629			62,395

Shareholders’ Equity:
Voting Shares - Unlimited Authorized; 2 Voting Shares Issued and Outstanding		100			100
Listed Shares - Unlimited Authorized; 62,301,674 and 57,918,371 Listed Shares Issued and Outstanding, Respectively		2,109,381			1,958,445
Retained Deficit		(392,120	)		(284,591	)
Accumulated Other Comprehensive Loss		(142,667	)		(178,340	)
Total Shareholders’ Equity		1,574,694			1,495,614

Total Liabilities and Shareholders’ Equity	$	1,699,971		$	1,583,661

The accompanying notes are an integral part of these statements.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Kinder Morgan Management, LLC and Subsidiary

The accompanying notes are an integral part of these statements.


	Year Ended December 31,
	2006				2005				2004
	Shares	Amount			Shares	Amount			Shares	Amount
	(Dollars in thousands)
Voting Shares:
Beginning Balance	2	$	100		2	$	100		2	$	100
Ending Balance	2		100		2		100		2		100

Listed Shares:
Beginning Balance	57,918,371		1,958,445		54,157,639		1,778,090		48,996,463		1,559,485
Listed Shares Issued	-		-		-		-		1,660,664		67,603
Share Dividends	4,383,303		186,519		3,760,732		168,788		3,500,512		137,733
Share Issuance Costs	-		(34	)	-		(40	)	-		(1,777	)
Revaluation of Kinder Morgan Energy Partners, L.P. Investment	-		(35,549	)	-		11,607		-		15,046
Ending Balance	62,301,674		2,109,381		57,918,371		1,958,445		54,157,639		1,778,090

Retained Deficit:
Beginning Balance			(284,591	)			(172,127	)			(109,516	)
Net Income			78,990				56,324				75,122
Share Dividends			(186,519	)			(168,788	)			(137,733	)
Ending Balance			(392,120	)			(284,591	)			(172,127	)

Accumulated Other Comprehensive Loss (Net of Tax Benefits):
Derivatives:
Beginning Balance			(178,287	)			(75,044	)			(24,484	)
Unrealized Gain (Loss) on Derivatives Utilized for Hedging Purposes			36,046				(103,243	)			(50,560	)
Ending Balance			(142,241	)			(178,287	)			(75,044	)
Foreign Currency Translation:
Beginning Balance			(53	)			63				-
Currency Translation Adjustment			108				(116	)			63
Ending Balance			55				(53	)			63
Adjustment to Initially Apply SFAS No. 158			(481	)			-				-
Ending Balance			(142,667	)			(178,340	)			(74,981	)

Total Shareholders’ Equity	62,301,676	$	1,574,694		57,918,373	$	1,495,614		54,157,641	$	1,531,082

The accompanying notes are an integral part of these statements.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

CONSOLIDATED STATEMENTS OF CASH FLOWS
Kinder Morgan Management, LLC and Subsidiary

Increase (Decrease) in Cash and Cash Equivalents


	Year Ended December 31,
	2006			2005			2004
	(In thousands)
Cash Flows From Operating Activities:
Net Income	$	78,990		$	56,324		$	75,122
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Deferred Income Taxes		44,165			32,124			38,360
Equity in Earnings of Kinder Morgan Energy Partners, L.P.		(123,155	)		(88,448	)		(113,482	)
Decrease (Increase) in Accounts Receivable		7,556			2,627			(10,196	)
(Increase) Decrease in Other Current Assets		(552	)		(773	)		773
(Decrease) Increase in Accounts Payable		(1,417	)		1,396			(1,490	)
(Decrease) Increase in Other Current Liabilities		(5,587	)		(3,250	)		10,913
Net Cash Flows Provided by Operating Activities		-			-			-

Cash Flows From Investing Activities:
Purchase of i-units of Kinder Morgan Energy Partners, L.P.		-			-			(67,528	)
Net Cash Flows Used in Investing Activities		-			-			(67,528	)

Cash Flows From Financing Activities:
Shares Issued		-			-			67,603
Share Issuance Costs		-			-			(75	)
Net Cash Flows Provided by Financing Activities		-			-			67,528

Net Increase in Cash and Cash Equivalents		-			-			-
Cash and Cash Equivalents at Beginning of Period		-			-			-
Cash and Cash Equivalents at End of Period	$	-		$	-		$	-

The accompanying notes are an integral part of these statements.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

General

Kinder Morgan Management, LLC is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., an indirect wholly owned subsidiary of Kinder Morgan, Inc., (a midstream energy company traded on the New York Stock Exchange under the symbol “KMI”), owns all of our voting shares. References to “we,” “our” or “the Company” are intended to mean Kinder Morgan Management, LLC and its consolidated subsidiary.

Significant Accounting Policies

(A) Basis of Presentation

Our consolidated financial statements include the accounts of Kinder Morgan Management, LLC and its wholly owned subsidiary, Kinder Morgan Services LLC. All material intercompany transactions and balances have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses. Actual results could differ from these estimates.

(B) Accounting for Investment in Kinder Morgan Energy Partners, L.P.

We use the equity method of accounting for our investment in Kinder Morgan Energy Partners, L.P., which investment is further described in Notes 3 and 4. Kinder Morgan Energy Partners, L.P. is a publicly traded limited partnership and is traded on the New York Stock Exchange under the symbol “KMP.” We record, in the period in which it is earned, our share of the earnings of Kinder Morgan Energy Partners, L.P. attributable to the i-units we own. We receive distributions from Kinder Morgan Energy Partners, L.P. in the form of additional i-units, which increase the number of i-units we own. We issue additional shares (or fractions thereof) of the Company to our existing shareholders in an amount equal to the additional i-units received from Kinder Morgan Energy Partners, L.P. At December 31, 2006, through our ownership of i-units, we owned approximately 27.0% of all of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner interests.

(C) Accounting for Share Distributions

Our board of directors declares and we make additional share distributions at the same times that Kinder Morgan Energy Partners, L.P. declares and makes distributions on the i-units to us, so that the number of i-units we own and the number of our shares outstanding remain equal. We account for the share distributions we make by charging retained earnings and crediting outstanding shares with amounts that equal the number of shares distributed multiplied by the closing price of the shares on the date the distribution is payable. As a result, we expect that our retained earnings will always be in a deficit position because (i) distributions per unit for Kinder Morgan Energy Partners, L.P. (which serve to reduce our retained earnings) are based on ”Available Cash” as defined by its partnership agreement, which amount generally exceeds the earnings per unit (which serve to increase our retained earnings) and (ii) the impact on our retained earnings attributable to our equity in the earnings of Kinder Morgan Energy Partners, L.P. is recorded after a provision for income taxes.

(D) Earnings Per Share

Both basic and diluted earnings per share are computed based on the weighted-average number of shares outstanding during each period, adjusted for share splits. There are no securities outstanding that may be converted into or exercised for shares.

(E) Income Taxes

Our long-term deferred income tax liability of $106.6 million and $62.4 million at December 31, 2006 and 2005, respectively, results from recognition of the increased investment associated with recording our equity in the earnings of Kinder Morgan Energy Partners, L.P. The effective tax rate utilized in computing our income tax provision was 35.9% for 2006, 36.3% for 2005 and 33.8% for 2004. The effective tax rate includes the 35% federal statutory rate, a provision for state income taxes and a reduction of 2.5% in 2004 due to a reduction in the state tax rate on our cumulative deferred tax liability.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

We entered into a tax indemnification agreement with Kinder Morgan, Inc. Pursuant to this tax indemnification agreement, Kinder Morgan, Inc. agreed to indemnify us for any tax liability attributable to our formation or our management and control of the business and affairs of Kinder Morgan Energy Partners, L.P. and for any taxes arising out of a transaction involving the i-units we own to the extent the transaction does not generate sufficient cash to pay our taxes with respect to such transaction.

(F) Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. No cash payments for interest or income taxes were made during the periods presented.

Capitalization

Our authorized capital structure consists of two classes of interests: (1) our listed shares and (2) our voting shares, collectively referred to in this document as our “shares.” Prior to the May 2001 initial public offering of our shares, our issued capitalization consisted of $100,000 contributed by Kinder Morgan, G.P., Inc. for two voting shares. At December 31, 2006, Kinder Morgan, Inc. owned approximately 10.3 million, or approximately 16.5% of our outstanding shares.

Business Activities and Related Party Transactions

At no time after our formation and prior to our initial public offering did we have any operations or own any interest in Kinder Morgan Energy Partners, L.P. Upon the closing of our initial public offering in May 2001, we became a limited partner in Kinder Morgan Energy Partners, L.P. and, pursuant to a delegation of control agreement, we assumed the management and control of its business and affairs. Under the delegation of control agreement, Kinder Morgan G.P., Inc. delegated to us, to the fullest extent permitted under Delaware law and the Kinder Morgan Energy Partners, L.P. partnership agreement, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions. Kinder Morgan Energy Partners, L.P. will either pay directly or reimburse us for all expenses we incur in performing under the delegation of control agreement and will be obligated to indemnify us against claims and liabilities provided that we have acted in good faith and in a manner we believed to be in, or not opposed to, the best interests of Kinder Morgan Energy Partners, L.P. and the indemnity is not prohibited by law. Kinder Morgan Energy Partners, L.P. consented to the terms of the delegation of control agreement including Kinder Morgan Energy Partners, L.P.’s indemnity and reimbursement obligations. We do not receive a fee for our service under the delegation of control agreement, nor do we receive any margin or profit on the expense reimbursement. We incurred approximately $215.5 million, $178.4 million and $167.4 million of expenses during the years ended December 31, 2006, 2005 and 2004, respectively, on behalf of Kinder Morgan Energy Partners, L.P. The expense reimbursements by Kinder Morgan Energy Partners, L.P. to us are accounted for as a reduction to the expense incurred by us. The net monthly balance payable or receivable from these activities is settled in cash in the following month. At December 31, 2006, $14.7 million, primarily a receivable from Kinder Morgan Energy Partners, L.P., is recorded in the caption “Accounts Receivable, Related Party” in the accompanying Consolidated Balance Sheet.

Kinder Morgan Services LLC is our wholly owned subsidiary and provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.’s operating partnerships and subsidiaries (collectively, the “Group”). Employees of KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., are assigned to work for one or more members of the Group. When they do so, they remain under our ultimate management and control. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with 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 its limited partnership agreement, Kinder Morgan Energy Partners, L.P. reimburses Kinder Morgan Services LLC for its share of these administrative costs, and such reimbursements are accounted for as described above. During the twelve months ended December 31, 2006, 2005 and 2004 the expenses totaled approximately $248.3, million, $215.3 million and $172.6 million, respectively.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

Summarized Financial Information for Kinder Morgan Energy Partners, L.P.

Following is summarized financial information for Kinder Morgan Energy Partners, L.P., a publicly traded limited partnership in which we own a significant interest. Additional information on Kinder Morgan Energy Partners, L.P.’s results of operations and financial position are contained in its 2006 Annual Report on Form 10-K, which is attached to this report as Exhibit 99.1.

Summarized Income Statement Information


	Year Ended December 31,
	2006		2005		2004
	(In thousands)
Operating Revenues	$	8,954,583	$	9,787,128	$	7,932,861
Operating Expenses		7,698,449		8,773,606		6,958,865
Operating Income	$	1,256,134	$	1,013,522	$	973,996

Income Before Cumulative Effect of a Change in Accounting Principle	$	972,143	$	812,227	$	831,578

Net Income	$	972,143	$	812,227	$	831,578

Summarized Balance Sheet Information


	As of December 31,
	2006		2005
	(In thousands)
Current Assets	$	1,036,745	$	1,215,224
Noncurrent Assets	$	11,209,649	$	10,708,238

Current Liabilities	$	2,885,699	$	1,808,885
Noncurrent Liabilities	$	5,288,443	$	6,458,506
Minority Interest	$	50,599	$	42,331

Recent Accounting Pronouncements

On September 15, 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements. This Statement defines fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles and, as a result, there is now a common definition of fair value to be used throughout generally accepted accounting principles.

This Statement applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements; however, for some entities the application of this Statement will change current practice. The changes to current practice resulting from the application of this Statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements.

This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 (January 1, 2008 for us), and interim periods within those fiscal years. This Statement is to be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, with certain exceptions. The disclosure requirements of this Statement are to be applied in the first interim period of the fiscal year in which this Statement is initially applied. We are currently reviewing the effects of this Statement.

On September 29, 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R). This Statement requires an employer to:

recognize the overfunded or underfunded status of a defined benefit pension plan or postretirement benefit plan (other than a multiemployer plan) as an asset or liability in its statement of financial position;


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and to disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations; and

recognize changes in the funded status of a plan in the year in which the changes occur through comprehensive income.

Past accounting standards only required an employer to disclose the complete funded status of its plans in the notes to the financial statements. Recognizing the funded status of a company’s benefit plans as a net liability or asset on its balance sheet will require an offsetting adjustment to “Accumulated other comprehensive income/loss” in shareholders’ equity. SFAS No. 158 does not change how pensions and other postretirement benefits are accounted for and reported in the income statement—companies will continue to follow the existing guidance in previous accounting standards. Accordingly, the amounts to be recognized in “Accumulated other comprehensive income/loss” representing unrecognized gains/losses, prior service costs/credits, and transition assets/obligations will continue to be amortized under the existing guidance. Those amortized amounts will continue to be reported as net periodic benefit cost in the income statement. Prior to SFAS No. 158, those unrecognized amounts were only disclosed in the notes to the financial statements.

According to the provisions of this Statement, an employer with publicly traded equity securities is required to initially recognize the funded status of a defined benefit pension plan or postretirement benefit plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006 (December 31, 2006 for us). In the year that the recognition provisions of this Statement are initially applied, an employer is required to disclose, in the notes to the annual financial statements, the incremental effect of applying this Statement on individual line items in the year-end statement of financial position. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008 (December 31, 2008 for us). In the year that the measurement date provisions of this Statement are initially applied, a business entity is required to disclose the separate adjustments of retained earnings and “Accumulated other comprehensive income/loss” from applying this Statement. We currently have no defined benefit pension and other postretirement benefit plans.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin requires a “dual approach” for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years’ misstatements, and a method that focuses on the period-end balance sheet. For us, SAB No. 108 was effective January 1, 2007. The adoption of this Bulletin did not have a material impact on our consolidated financial statements, and we will apply this guidance prospectively.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. For us, this Interpretation was effective January 1, 2007, and the adoption of this Interpretation had no effect on our consolidated financial statements.

In June 2006, the FASB ratified the consensuses reached by the Emerging Issues Task Force on EITF 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation). According to the provisions of EITF 06-3:

taxes assessed by a governmental authority that are directly imposed on a revenue-producing transaction between a seller and a customer may include, but are not limited to, sales, use, value added, and some excise taxes; and

that the presentation of such taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board Opinion No. 22 (as amended), Disclosure of Accounting Policies. In addition, for any such taxes that are reported on a gross basis, a company should disclose the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The disclosure of those taxes can be done on an aggregate basis.

EITF 06-3 should be applied to financial reports for interim and annual reporting periods beginning after December 15, 2006 (January 1, 2007 for us). Because the provisions of EITF 06-3 require only the presentation of additional disclosures, we do not expect the adoption of EITF 06-3 to have an effect on our consolidated financial statements.

On February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This Statement provides companies with an option to report selected financial assets and liabilities at fair value.


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K

The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.

SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed above, and SFAS No. 107 Disclosures about Fair Value of Financial Instruments.

This Statement is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007 (January 1, 2008 for us). Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157. We are currently reviewing the effects of this Statement.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly Operating Results for 2006 and 2005


	2006-Three Months Ended
	March 31		June 30		September 30		December 31
	(In thousands except per share amounts)
Equity in Earnings of Kinder Morgan Energy Partners, L.P.	$	31,174	$	31,353	$	24,064	$	36,564
Provision for Income Taxes		11,322		11,057		8,575		13,211
Net Income	$	19,852	$	20,296	$	15,489	$	23,353

Earnings Per Share, Basic and Diluted	$	0.34	$	0.34	$	0.26	$	0.38

Number of Shares Used in Computing Basic and Diluted Earnings Per Share		58,428		59,480		60,600		61,747


	2005-Three Months Ended
	March 31		June 30		September 30		December 31
	(In thousands except per share amounts)
Equity in Earnings (Losses) of Kinder Morgan Energy Partners, L.P.	$	29,422	$	27,825	$	32,621	$	(1,420	)
Income Tax Provision (Benefit)		10,686		10,106		11,848		(516	)
Net Income (Loss)	$	18,736	$	17,719	$	20,773	$	(904	)

Earnings (Loss) Per Share, Basic and Diluted	$	0.34	$	0.32	$	0.37	$	(0.02	)

Number of Shares Used in Computing Basic and Diluted Earnings Per Share		54,646		55,632		56,571		57,472

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

We do not directly have oil and gas producing activities, however, our equity method investee, Kinder Morgan Energy Partners, L.P., does have significant oil and gas producing activities. The Supplementary Information on Oil and Gas Producing Activities that follows is presented as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities, and represents our equity interest in the oil and gas producing activities of Kinder Morgan Energy Partners, L.P. Our proportionate share of Kinder Morgan Energy Partners, L.P.’s capitalized costs, costs incurred and results of operations from oil and gas producing activities consisted of the following:


Item 8. Financial Statements and Supplementary Data. (continued)	KMR Form 10-K


	December 31,
	2006		2005		2004
	(In thousands)
Net Capitalized Costs	$	330,324	$	287,433	$	245,006
Costs Incurred for the Year Ended		79,055		74,264		75,294
Results of Operations for the Year Ended		21,204		30,939		21,054

Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations or declines based upon future conditions. Proved developed reserves are the quantities of crude oil, natural gas liquids and natural gas expected to be recovered through existing investments in wells and field infrastructure under current operating conditions. Proved undeveloped reserves require additional investments in wells and related infrastructure in order to recover the production.

The standardized measure of discounted cash flows is based on assumptions including year-end market pricing, future development and production costs and projections of future abandonment costs. A discount factor of 10% is applied annually to the future net cash flows.

The table below represents our proportionate share of Kinder Morgan Energy Partners, L.P.’s (i) estimate of proved crude oil, natural gas liquids and natural gas reserves and (ii) standardized measure of discounted cash flows.


	December 31,
	2006		2005		2004		2003
	(Dollars in thousands)
Proved Reserves:
Crude Oil (MBbls)		32,850		36,584		31,723		29,619
Natural Gas Liquids (MBbls)		2,738		4,892		5,191		4,131
Natural Gas (MMcf)¹		77		555		408		836
Standardized Measure of Discounted Cash Flows for the Year Ended	$	584,994	$	792,497	$	524,304	$	357,589

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Item 9.

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

None.

Item 9A.

Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2006, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies

Item 9A. Controls and Procedures. (continued) KMR Form 10-K

or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2006.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their attestation report which is included elsewhere in this report.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information.

None

KMR Form 10-K

PART III

Item 10.

Directors, Executive Officers and Corporate Governance.

Set forth below is certain information concerning our directors and executive officers. All directors are elected annually by, and may be removed by, Kinder Morgan G.P., Inc. as the sole holder of our voting shares. All officers serve at the discretion of our board of directors. In addition to the individuals named below, Kinder Morgan, Inc. was one of our directors until its resignation in January 2003.


Name	Age	Position
Richard D. Kinder	62	Director, Chairman and Chief Executive Officer
C. Park Shaper	38	Director and President
Steven J. Kean	45	Executive Vice President and Chief Operating Officer
Edward O. Gaylord	75	Director
Gary L. Hultquist	63	Director
Perry M. Waughtal	71	Director
Kimberly A. Dang	37	Vice President, Investor Relations and Chief Financial Officer
Jeffrey R. Armstrong	38	Vice President (President, Terminals)
Thomas A. Bannigan	53	Vice President (President, Products Pipelines)
Richard T. Bradley	51	Vice President (President, CO₂)
David D. Kinder	32	Vice President, Corporate Development and Treasurer
Joseph Listengart	38	Vice President, General Counsel and Secretary
Scott E. Parker	46	Vice President (President, Natural Gas Pipelines)
James E. Street	50	Vice President, Human Resources and Administration

Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan, Inc. in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder was elected President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2004 and served as President until May 2005. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development and Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc.

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

Steven J. Kean is Executive Vice President and Chief Operating Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Inc. Mr. Kean was elected Executive Vice President and Chief Operating Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Inc. in January 2006. He served as Executive Vice President, Operations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Inc. from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. Until December 2001, Mr. Kean was Executive Vice President and Chief of Staff of Enron Corp. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State University in May 1982.

Edward O. Gaylord is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the Chairman of the Board of Directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel.


Item 10. Directors and Executive Officers of the Registrant. (continued)	KMR Form 10-K

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

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

Kimberly A. Dang is Vice President, Investor Relations and Chief Financial Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mrs. Dang was elected Chief Financial Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. She served as Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2004 to May 2005. She was elected Vice President, Investor Relations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in July 2002. From November 2001 to July 2002, she served as Director, Investor Relations. From May 2001 until November 2001, Mrs. Dang was an independent financial consultant. From September 2000 until May 2001, she served as an associate and later a principal at Murphee Venture Partners, a venture capital firm. Mrs. Dang has received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University and a Bachelor of Business Administration degree in accounting from Texas A&M University.

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

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

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

David D. Kinder is Vice President, Corporate Development and Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. Mr. Kinder was elected Treasurer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. He was elected Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in October 2002. He served as manager of corporate development for Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. from January 2000 to October 2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.

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

Scott E. Parker is Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. He was elected Vice President (President, Natural Gas Pipelines) of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan, Inc. in May 2005. Mr. Parker served as President of


Item 10. Directors and Executive Officers of the Registrant. (continued)	KMR Form 10-K

Kinder Morgan, Inc.’s Natural Gas Pipeline Company of America, or NGPL, from March 2003 to May 2005. Mr. Parker served as Vice President, Business Development of NGPL from January 2001 to March 2003. He held various positions at NGPL from January 1984 to January 2001. Mr. Parker holds a Bachelor’s degree in accounting from Governors State University.

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

Corporate Governance

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

We have not, nor has Kinder Morgan Energy Partners, L.P. nor its general partner made, within the preceding three years, contributions to any tax-exempt organization in which any of our or Kinder Morgan Energy Partners, L.P.’s independent directors serves as an executive officer that in any single fiscal year exceeded the greater of $1 million or 2% of such tax-exempt organization’s consolidated gross revenues.

On April 11, 2006, our chief executive officer certified to the New York Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, that as of April 11, 2006, he was not aware of any violation by us of the New York Stock Exchange’s Corporate Governance listing standards. We have also filed as an exhibit to this report the Sarbanes-Oxley Act Section 302 certifications regarding the quality of our public disclosure.

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

Interested parties may contact our lead director, the chairpersons of any of the board’s committees, the independent directors as a group or the full board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas 77002, Attention: General Counsel, or by e-mail within the “Contact Us” section of our internet website, at www.kindermorgan.com. Any communication should specify the intended recipient.

Section 16(a) Beneficial Ownership Reporting Compliance

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

Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2006.

Item 11. Executive Compensation

All of our individual executive officers and directors serve in the same capacities for Kinder Morgan G.P., Inc. Certain of those executive officers also serve as executive officers of Kinder Morgan, Inc. All information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and their respective affiliates; consequently, in


Item 11. Executive Compensation. (continued)	KMR Form 10-K

this Item 11, “we,” “our” or “us” refers to Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and, where appropriate, Kinder Morgan, Inc.

Compensation Discussion and Analysis

Program Objectives

We are a publicly traded Delaware limited liability company. We are a limited partner in Kinder Morgan Energy Partners, L.P., and manage and control its business and affairs pursuant to a delegation of control agreement. We seek to attract and retain executives who will help us achieve our primary business strategy objective of growing the value of Kinder Morgan Energy Partners, L.P.’s portfolio of businesses for the benefit of our shareholders and its unitholders. To help accomplish this goal, we have designed an executive compensation program that rewards individuals with competitive compensation that consists of a mix of cash, benefit plans and long-term compensation, with a majority of executive compensation tied to the “at risk” portions of the annual cash bonus and long-term equity compensation.

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

Our executive compensation program is principally comprised of the following three elements:

base cash salary;

possible annual cash bonus (reflected in the Summary Compensation Table below as Non-Equity Incentive Plan Compensation); and

possible long-term equity awards, namely grants of restricted Kinder Morgan, Inc. stock and, in previous years, grants of options to acquire shares of Kinder Morgan, Inc. common stock.

It is our current philosophy to pay our executive officers a base salary not to exceed $200,000 per year, which is below base salaries for comparable positions in the marketplace. In addition, we believe that the compensation of our Chief Executive Officer, Chief Financial Officer and the executives named below, collectively referred to in this Item 11 as our named executive officers, should be directly and materially tied to the financial performance of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P., and should be aligned with the interests of Kinder Morgan, Inc. stockholders and Kinder Morgan Energy Partners, L.P. unitholders. Therefore, the majority of our named executive officers’ compensation is allocated to the “at risk” portions of our compensation program—the annual cash bonus and the long-term equity compensation. For 2006, our executive compensation was weighted toward the cash bonus, payable on the basis of achieving (i) an earnings per share target by Kinder Morgan, Inc.; and (ii) a cash distribution per common unit target by Kinder Morgan Energy Partners, L.P. Prior to 2003, we used both Kinder Morgan, Inc. stock options and restricted Kinder Morgan, Inc. stock as the principal components of long-term executive compensation, and beginning in 2003, we used grants of restricted stock exclusively as the principal component of long-term executive compensation.

Grants of restricted Kinder Morgan, Inc. stock are made to encourage our executive officers to manage from the perspective of owners with an equity stake and our approach to equity compensation is designed to balance the business objectives of fair and reasonable executive pay with the business objectives of equityholder interests. We are very sensitive to making large awards of Kinder Morgan, Inc. restricted stock or Kinder Morgan, Inc. stock options to our executive officers because such large awards dilute the ownership of Kinder Morgan, Inc.’s stockholders. Therefore, we seek to balance the dilutive effect of such stock awards to Kinder Morgan, Inc.’s existing stockholders with our need to attract and retain key employees.

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

We have endeavored to design our executive compensation program and practices with appropriate consideration of all tax, accounting, legal and regulatory requirements. Section 162(m) of the Internal Revenue Code limits the deductibility of certain compensation for our executive officers to $1,000,000 of compensation per year; however, if specified conditions are


Item 11. Executive Compensation. (continued)	KMR Form 10-K

met, certain compensation may be excluded from consideration of the $1,000,000 limit. Since the bonuses we pay to our executive officers are paid under Kinder Morgan, Inc.’s stockholder-approved 2005 Annual Incentive Plan as a result of reaching designated financial targets established by Kinder Morgan, Inc.’s compensation committee, we expect that all compensation paid to our executives will be deductible by Kinder Morgan, Inc.

Behaviors Designed to Reward

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

Unlike many companies, we have no executive perquisites and, with respect to our United States-based executives, we have no supplemental executive retirement, non-qualified supplemental defined benefit/contribution, deferred compensation or split dollar life insurance programs. We have no executive company cars or executive car allowances nor do we offer or pay for financial planning services. Additionally, we do not own any corporate aircraft and we do not pay for executives to fly first class. We are currently below competitive levels for comparable companies in this area of our compensation package, however, we have no current plans to change our policy of not offering such executive benefits or perquisite programs.

At his request, Mr. Kinder, our Chairman and Chief Executive Officer, receives $1 of base salary per year. Additionally, Mr. Kinder has requested that he receive no annual bonus, stock or unit grants, or other compensation. Mr. Kinder does not have any deferred compensation, supplemental retirement or any other special benefit, compensation or perquisite arrangement. He wishes to be rewarded strictly on the basis of stock performance which impacts the value of his holdings of Kinder Morgan, Inc. common stock, Kinder Morgan Energy Partners, L.P. common units and our shares. Each year Mr. Kinder reimburses us for his portion of health care premiums and parking expenses.

Elements of Compensation

As outlined above, our executive compensation program is principally comprised of the following three elements: a base cash salary; a possible annual cash bonus; and a possible long-term equity award. With regard to our executive officers other than our Chief Executive Officer, Kinder Morgan, Inc.’s and our compensation committees review and approve annually the financial goals and objectives of both Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. that are relevant to the compensation of our executive officers. Generally following the regularly scheduled fourth quarter board meetings in each year, the committees solicit information from other directors, the Chief Executive Officer and other relevant members of senior management regarding the performance of our executive officers other than our Chief Executive Officer during that year. Our Chief Executive Officer makes compensation recommendations to the committees with respect to our executive officers, other than himself. The committees obtain the information and the recommendations prior to the regularly scheduled first quarter board meetings.

Annually, at Kinder Morgan, Inc.’s and our regularly scheduled first quarter board meetings, the committees evaluate the performance of our executive officers other than our Chief Executive Officer and make determinations regarding the terms of their continued employment and compensation for that year. If the committees deem it advisable, they may, rather than determine the terms of continued employment and compensation for executive officers (other than the Chief Executive Officer), make a recommendation with respect thereto to the independent members of the board who make the determination at the first quarter board meetings. The committees also determine bonuses for the prior year based on the performance targets set therefore, and set performance targets for the present year for bonus and other relevant purposes.

If any of our executive officers is also an executive officer of Kinder Morgan, Inc. or Kinder Morgan G.P., Inc., the committees’ compensation determination or recommendation (i) may be with respect to the aggregate compensation to be received by such officer from Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and us that is to be allocated among them in accordance with procedures approved by the committees, if such aggregate compensation set by the committee or the board of Kinder Morgan, Inc. and that set by the committee or our board are the same, or alternatively (ii) may be with respect to the compensation to be received by such executive officers from Kinder Morgan, Inc., Kinder Morgan G.P., Inc. or us, as the case may be, in which case such compensation will not be allocated among Kinder Morgan, Inc., on the one hand, and Kinder Morgan G.P., Inc, Kinder Morgan Energy Partners, L.P. and us, on the other. Further, if any of our executive officers is also an executive officer of Kinder Morgan, Inc., the committees may, to the extent they believe necessary or desirable, exchange information with respect to evaluation and compensation recommendations with each other. Thereafter, the committees or the Chief Executive Officer will discuss the committees’ evaluation and the determination as to compensation with the executive officers.

In addition, the compensation committees have the sole authority to retain (and terminate as necessary) and compensate any compensation consultants, counsel and other firms of experts to advise them as they determine necessary or appropriate. The committees have the sole authority to approve any such firm's fees and other retention terms, and Kinder Morgan Energy


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Partners and Kinder Morgan, Inc., as applicable, will make adequate provision for the payment of all fees and other compensation, approved by the committees, to any such firm employed by the committees. The committees also have sole authority to determine if any compensation consultant is to be used to assist in the evaluation of director, Chief Executive Officer or senior executive compensation and will have sole authority to retain and terminate any such compensation consultant and to approve the consultant's fees and other retention terms.

Base Salary

This includes base salary, which is paid in cash. All of our executive officers, with the exception of our Chairman and Chief Executive Officer who receives $1 of base salary per year as described above, earn a base salary not to exceed $200,000 per year. Generally, we believe that our executive officers’ base salaries are below base salaries for executives in similar positions and with similar responsibilities at comparable companies of corresponding size and scope.

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

Our possible annual cash bonuses are provided for under Kinder Morgan, Inc.’s 2005 Annual Incentive Plan, which became effective January 18, 2005 and which is referred to in this report as the Kinder Morgan, Inc. Annual Incentive Plan. The overall purpose of the Kinder Morgan, Inc. Annual Incentive Plan is to increase our executive officers’ and our employees’ personal stake in the continued success of Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. by providing them additional incentives through the possible payment of annual cash bonuses. Under the plan, annual cash bonuses may be paid to our executive officers and other employees depending on a variety of factors, including their individual performance, Kinder Morgan, Inc.’s financial performance, the financial performance of Kinder Morgan, Inc.’s subsidiaries (including Kinder Morgan Energy Partners, L.P.), and safety and environmental goals.

The plan is administered by the compensation committee of Kinder Morgan, Inc.’s board of directors, which consists of three or more directors, each of whom qualifies as an “outside director” for purposes of the Internal Revenue Code. The compensation committee is authorized to grant awards under the plan, interpret the plan, adopt rules and regulations for carrying out the plan, and make all determinations necessary or advisable for the administration of the plan.

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

The plan consists of two components: the executive plan component and the non-executive plan component. Our Chairman and Chief Executive Officer and all employees who report directly to the Chairman are eligible for the executive plan component; however, as stated elsewhere in this report, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer, does not participate under the plan. As of January 31, 2007, excluding Mr. Richard D. Kinder, 13 of our current executive officers were eligible to participate in the executive plan component. All other U.S. eligible employees were eligible for the non-executive plan component.

The Kinder Morgan, Inc. compensation committee determines which of the eligible employees will be eligible to participate under the executive plan component of the Kinder Morgan, Inc. Annual Incentive Plan for any given year. At or before the start of each calendar year (or later, to the extent allowed under Internal Revenue Code regulations), performance objectives for that year are identified. The performance objectives are based on one or more of the criteria set forth in the plan. The Kinder Morgan, Inc. compensation committee establishes a bonus opportunity for each executive officer, which is the amount of the bonus the executive officer will earn if the performance objectives are fully satisfied. The compensation committee may specify a minimum acceptable level of achievement of each performance objective below which no bonus is payable with respect to that objective. The compensation committee may set additional levels above the minimum (which may also be above the targeted performance objective), with a formula to determine the percentage of the bonus opportunity to be earned at each level of achievement above the minimum. Performance at a level above the targeted performance objective may entitle the executive officer to earn a bonus in excess of 100% of the bonus opportunity. However, the maximum payout to any individual under the Kinder Morgan, Inc. Annual Incentive Plan for any year is $2.0 million, and the Kinder Morgan, Inc. compensation committee has the discretion to reduce the bonus amount in any performance period.

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

Kinder Morgan, Inc.’s earnings per share;

Kinder Morgan, Inc. cash dividends to its stockholders;

Kinder Morgan, Inc.’s earnings before interest and taxes or earnings before interest, taxes and corporate charges, or the earnings before interest and taxes or earnings before interest, taxes and corporate charges of one of its subsidiaries or business units;


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Kinder Morgan, Inc.’s net income or the net income of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s revenues or the revenues of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s unit revenues minus unit variable costs or the unit revenues minus unit variable costs of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s return on capital, return on equity, return on assets, or return on invested capital, or the return on capital, return on equity, return on assets, or return on invested capital of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s cash flow return on assets or cash flows from operating activities, or the cash flow return on assets or cash flows from operating activities of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s capital expenditures or the capital expenditures of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s operations and maintenance expense or general and administrative expense, or the operations and maintenance expense or general and administrative expense of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s debt-equity ratios and key profitability ratios, or the debt-equity ratios and key profitability ratios of one of its subsidiaries or business units; or

Kinder Morgan, Inc.’s stock price.

The Kinder Morgan, Inc. compensation committee set two performance objectives for 2006 under both the executive plan component and the non-executive plan component. The 2006 performance objectives were $3.28 in cash distributions per common unit at Kinder Morgan Energy Partners, L.P., and $5.00 in earnings per share at Kinder Morgan, Inc. These targets were the same as Kinder Morgan Energy Partners, L.P.’s and Kinder Morgan, Inc.’s previously disclosed 2006 budget expectations. At the end of 2006, the Kinder Morgan, Inc. compensation committee determined and certified in writing the extent to which the performance objectives had been attained and the extent to which the bonus opportunity had been earned under the formula previously established by the Kinder Morgan, Inc. compensation committee. Because payments under the plan for our executive officers are determined by comparing actual performance to the performance objectives established by the compensation committee each year for eligible executive officers chosen to participate for that year, it is not possible to accurately predict any amounts that will actually be paid under the executive plan portion of the plan over the life of the plan.

The below table sets forth the bonus opportunities that would have been payable to our executive officers if the performance objectives established by the Kinder Morgan, Inc. compensation committee for 2006 had been 100% achieved. The Kinder Morgan, Inc. compensation committee may, at its sole discretion, reduce the amount of the bonus actually paid to any executive officer under the plan from the amount of any bonus opportunity open to such executive officer.

Kinder Morgan, Inc. Annual Incentive Plan
Bonus Opportunities for 2006¹


Name and Principal Position	Dollar Value

Richard D. Kinder, Chairman and Chief Executive Officer	$	—	²

Kimberly A. Dang, Vice President and Chief Financial Officer		1,000,000	³

Jeffrey R. Armstrong, Vice President (President, Terminals)		1,000,000	³

David D. Kinder, Vice President Corporate Development and Treasurer		1,000,000	³

Steven J. Kean, Executive Vice President and Chief Operating Officer		1,500,000	⁴

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

Scott E. Parker, Vice President (President, Natural Gas Pipelines)		1,000,000	³

C. Park Shaper, Director and President		1,500,000	⁴

__________

No stock, stock options, stock appreciation rights, restricted stock or similar awards are payable under the plan.

Declined to participate.


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Under the plan, for 2006, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $500,000 in bonus opportunities would have been open; if both of the targets had been exceeded by 10%, $1,500,000 in bonus opportunities would have been open. The Kinder Morgan, Inc. compensation committee may, in its sole discretion, reduce the award payable to any participant for any reason.

⁴

Under the plan, for 2006, if neither of the targets was met, no bonus opportunities would have been provided; if one of the targets was met, $750,000 in bonus opportunities would have been open; if both of the targets had been exceeded by 10%, $2,000,000 in bonus opportunities would have been open. The Kinder Morgan, Inc. compensation committee may, in its sole discretion, reduce the award payable to any participant for any reason.

In 2006, excluding the impairment charge resulting from our entering into a definitive agreement to sell our Terasen Gas business segment, Kinder Morgan, Inc. exceeded its established target, but Kinder Morgan Energy Partners, L.P. did not achieve its established target. Excluding Mr. Richard D. Kinder, who does not participate in the plan, our top three executive officers (Messrs. Shaper, Kean and Listengart) voluntarily elected to take zero bonuses for work done in 2006. The Kinder Morgan, Inc. compensation committee agreed to the executives’ request for zero bonuses, but wanted to make note that it was no reflection on any of the executives’ personal performance for the year. It was also noted and reflected that each of our other executive officers’ bonus was reduced in accordance with past practice and in light of the making of just one target. Mr. Parker’s bonus was paid $500,000 from the plan according to the plan terms, and $350,000 from outside the plan as a discretionary bonus.

The plan was established, in part, to enable the portion of an officer’s or other employee’s annual bonus based on objective performance criteria to qualify as “qualified performance–based compensation” under the Internal Revenue Code. “Qualified performance–based compensation” is deductible by Kinder Morgan Energy Partners, L.P. for tax purposes. The tax deduction available with respect to compensation paid to executive officers is limited, unless the compensation qualifies as performance-based under the Internal Revenue Code. The requirements for performance-based compensation include the following:

the compensation must be paid based solely on the attainment of objective performance measures established by a committee of outside directors, and

the plan providing for such compensation must be approved by Kinder Morgan, Inc. stockholders.

The Kinder Morgan, Inc. Annual Incentive Plan is a bonus plan that enables the portion of an officer or employee's annual bonus based on objective performance criteria to qualify as performance-based. Accordingly, that amount is deductible without regard to the deduction limit otherwise imposed by the Internal Revenue Code. If a bonus paid under the plan to an individual is in excess of the bonus opportunity set by the compensation committee, Section 162(m) of the Internal Revenue Code could limit the deductibility of the bonus paid. Consequently, the compensation committee set bonus opportunities under the plan for 2006 for the executive officers at dollar amounts in excess of that which were expected to actually be paid under the plan.

Kinder Morgan, Inc.’s Board of Directors may amend the plan from time to time without Kinder Morgan, Inc. stockholder approval except as required to satisfy the Internal Revenue Code or any applicable securities exchange rules. Awards may be granted under the plan for calendar years 2007 through 2009, unless the plan is terminated earlier by the Kinder Morgan, Inc. Board. However, the plan will remain in effect until payment has been completed with respect to all awards granted under the plan prior to its termination.

Restricted Kinder Morgan, Inc. Stock Awards

This includes grants of restricted Kinder Morgan, Inc. stock under Kinder Morgan, Inc.’s Amended and Restated 1999 Stock Plan, referred to in this report as the Kinder Morgan, Inc. stock plan. The Kinder Morgan, Inc. stock plan allows for grants of restricted Kinder Morgan, Inc. stock and non-qualified Kinder Morgan, Inc. stock options. We believe the plan permits us to keep pace with changing developments in compensation and benefit programs, making us competitive with those companies that offer incentives to attract and retain employees.

The purposes of the Kinder Morgan, Inc. stock plan are to:

enable the employees of Kinder Morgan, Inc. and the employees of its subsidiaries to develop a sense of proprietorship and personal involvement in Kinder Morgan, Inc.’s financial success and the financial success of its subsidiaries, including us; and

encourage those employees to remain with and devote their best efforts to Kinder Morgan, Inc.’s business and the business of its subsidiaries, including Kinder Morgan Energy Partners, L.P.

Officers and other employees of Kinder Morgan, Inc. and other entities in which they have a direct or indirect interest are eligible to participate in the plan. Kinder Morgan, Inc.’s compensation committee, which administers the plan, has the sole


Item 11. Executive Compensation. (continued)	KMR Form 10-K

discretion to select participants from among eligible persons. Directors who are not employees are not eligible to participate in the plan. The aggregate number of shares of Kinder Morgan, Inc. common stock which may be issued under the plan with respect to options, restricted stock and restricted stock units may not exceed 10,500,000, subject to adjustment for certain transactions affecting the common stock. Lapsed, forfeited or canceled options, and shares subject to forfeited restricted stock units, will not count against this limit and can be regranted under the plan. Options with respect to more than 1,000,000 shares of Kinder Morgan, Inc. common stock, restricted stock with respect to more than 500,000 shares of Kinder Morgan, Inc. common stock and restricted stock units with respect to more than 100,000 shares of Kinder Morgan, Inc. common stock may not be granted to any one employee during any five year period. The shares issued under the plan may be issued from shares held in treasury or from authorized but unissued shares.

The Kinder Morgan, Inc. stock plan provides for the grant of:

nonqualified stock options;

stock appreciation rights in tandem with stock options;

restricted stock; and

restricted stock units.

Awards may be granted individually, in combination, or in tandem as determined by the compensation committee. Kinder Morgan, Inc.’s Board of Directors may amend the plan without Kinder Morgan, Inc. stockholder approval, unless that approval is required by applicable law, rules, regulations or stock exchange requirements; however, Kinder Morgan, Inc.’s Board of Directors may not amend the plan in such a way that would impair the rights of a participant under an award without the consent of such participant, or that would decrease any authority granted to the Kinder Morgan, Inc. compensation committee in contravention of Rule 16b-3 under the Securities Exchange Act of 1934, as amended. In addition, Kinder Morgan, Inc.’s Board of Directors may terminate the plan at any time.

The Kinder Morgan, Inc. compensation committee establishes the form and terms of each grant of restricted stock, and each grant is evidenced by a written agreement. Shares of restricted stock are subject to "forfeiture restrictions" that restrict the transferability of the shares and obligate the participant to forfeit and surrender the shares under certain circumstances, such as termination of employment. The Kinder Morgan, Inc. compensation committee may decide that forfeiture restrictions on restricted stock will lapse upon the restricted stock holder's continued employment for a specified period of time, the attainment of one or more performance targets established by the Kinder Morgan, Inc. compensation committee, the occurrence of any event or the satisfaction of any condition specified by the Kinder Morgan, Inc. compensation committee, or a combination of any of these. The performance targets may be based on:

the price of a share of Kinder Morgan, Inc. stock or of the equity of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s earnings per share or the earnings per share of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s total stockholder value or the total stockholder value of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s dividends or distributions or the dividends or distributions of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s revenues or the revenues of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s debt/equity ratio, interest coverage ratio or indebtedness/earnings before or after interest, taxes, depreciation and amortization ratio, or such ratios with respect to one of its subsidiaries or business units;

Kinder Morgan, Inc.’s cash coverage ratio or the cash coverage ratio with respect to one of its subsidiaries or business units;

Kinder Morgan, Inc.’s net income (before or after taxes) or the net income (before or after taxes) of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s cash flow or cash flow return on investments or the cash flow or cash flow return on investments of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s earnings before or after interest, taxes, depreciation, and/or amortization or earnings before or after interest, taxes, depreciation, and/or amortization of one of its subsidiaries or business units;


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Kinder Morgan, Inc.’s economic value added or the economic value added of one of its subsidiaries or business units;

Kinder Morgan, Inc.’s return on stockholders' equity or the return on stockholders' equity of one of its subsidiaries or business units; or

the payment of a bonus under the Kinder Morgan, Inc. Annual Incentive Plan as a result of the attainment of performance goals based on one or more of the criteria set forth above.

Each grant of restricted stock may have different forfeiture restrictions, in the discretion of the Kinder Morgan, Inc. compensation committee. The Kinder Morgan, Inc. compensation committee may, in its sole discretion, prescribe additional terms, conditions or restrictions relating to restricted stock, including, but not limited to, rules pertaining to the termination of employment (by retirement, disability, death or otherwise) of a participant prior to the lapse of the forfeiture restrictions, and terms related to tax matters.

Unless otherwise provided for in a written agreement, a participant will have the right to receive dividends with respect to restricted stock, to vote the stock and to enjoy all other stockholder rights, except that:

the participant will not be entitled to delivery of the stock certificate unless and until the forfeiture restrictions have lapsed;

Kinder Morgan, Inc. will retain custody of the stock unless and until the forfeiture restrictions have lapsed;

the participant may not sell, transfer, pledge, exchange, hypothecate or otherwise dispose of the stock unless and until the forfeiture restrictions have lapsed; and

a breach by a participant of the terms and conditions established by the Kinder Morgan, Inc. compensation committee pursuant to the restricted stock agreement will cause a forfeiture of the restricted stock by the participant.

Unless otherwise provided for in a written agreement, dividends payable with respect to restricted stock will be paid to a participant in cash on the day on which the corresponding dividend on shares is paid to Kinder Morgan, Inc. stockholders, or as soon as administratively feasible thereafter, but no later than the fifteenth day of the third calendar month following the day on which the corresponding dividend is paid to Kinder Morgan, Inc. stockholders. The Kinder Morgan, Inc. compensation committee may, in its sole discretion, decide that a participant's right to receive dividends on restricted stock is subject to the attainment of one or more performance targets based on the criteria listed above.

The Kinder Morgan, Inc. compensation committee at any time may accelerate the time or conditions under which the forfeiture restrictions lapse. However, except in the event of a corporate change (as defined in the plan), the Kinder Morgan, Inc. compensation committee may not take any such action with respect to “covered employees” (within the meaning of Treasury Regulation § 1.162-27(c)(2)) if such restricted stock has been designed to meet the exception for performance-based compensation under Section 162(m) of the Internal Revenue Code unless the performance targets with respect to the restricted stock have been attained.

For the year ended December 31, 2006, no restricted stock or options to purchase shares of Kinder Morgan, Inc. were granted to any of our executive officers.

Other Compensation

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

For employees hired on or prior to December 31, 2004, all contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Employer contributions for employees hired on or after January 1, 2005 will vest on the second anniversary of the date of hire. Effective October 1, 2005, for new employees of Kinder Morgan Energy Partners, L.P.’s Terminals business segment, a tiered employer contribution schedule was implemented. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for service


Item 11. Executive Compensation. (continued)	KMR Form 10-K

between two and five years, and 4% for service of five years or more. All employer contributions for employees of our Terminals business segment hired after October 1, 2005 will vest on the fifth anniversary of the date of hire.

At its July 2006 meeting, the compensation committee of the Kinder Morgan, Inc. board of directors approved a special contribution of an additional 1% of base pay into the Savings Plan for each eligible employee. Each eligible employee will receive an additional 1% company contribution based on eligible base pay each pay period beginning with the first pay period of August 2006 and continuing through the last pay period of July 2007. The additional 1% contribution is in the form of Kinder Morgan, Inc. common stock (the same as the current 4% contribution) and does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive. It may be converted to any other Savings Plan investment fund at any time and it will vest according to the same vesting schedule described in the preceding paragraph. Since this additional 1% company contribution is discretionary, KMI compensation committee approval will be required annually for each additional contribution. During the first quarter of 2007, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2006.

Additionally, in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option) to a separate participant account was added to the Savings Plan as an additional benefit to all participants. Unlike traditional 401(k) plans, where participant contributions are made with pre-tax dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k) contributions are made with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free if they occur after both (i) the fifth year of participation in the Roth 401(k) option, and (ii) attainment of age 59 ½, death or disability. The employer contribution will still be considered taxable income at the time of withdrawal.

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

The following table sets forth the estimated actuarial present value of each named executive officer’s accumulated pension benefit as of December 31, 2006, under the provisions of the Kinder Morgan Cash Balance Retirement Plan. With respect to our executive officers, the benefits were computed using the same assumptions used for financial statement purposes, assuming current remuneration levels without any salary projection, and assuming participation until normal retirement at age sixty-five. These benefits are subject to federal and state income taxes, where applicable, but are not subject to deduction for social security or other offset amounts.


Pension Benefits
Name	Plan Name	Current Credited Yrs of Service	Present Value of Accumulated Benefit¹			Contributions During 2006
Richard D. Kinder	Cash Balance	6		$	-		$	-
Kimberly A. Dang	Cash Balance	5			24,114			6,968
Jeffrey R. Armstrong	Cash Balance	6			40,534			7,726
David D. Kinder	Cash Balance	6			32,114			7,337
Steven J. Kean	Cash Balance	5			33,957			7,422
Joseph Listengart	Cash Balance	6			42,885			7,835
Scott E. Parker	Cash Balance	8			62,385			8,735
C. Park Shaper	Cash Balance	6			42,885			7,835

__________

The present values in the Pension Benefits table are based on certain assumptions-including a 6% discount rate, RP 2000 mortality (post-retirement only), 5% cash balance interest crediting rate, and lump sums calculated using a 5% interest rate and IRS mortality. We assumed benefits would commence at normal retirement date or unreduced retirement date, if earlier. No death or turnover was assumed prior to retirement date.

Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with Kinder Morgan, Inc. pursuant to which he agreed to serve as its Chairman and Chief Executive Officer. His employment agreement provides for a term of three years and one year extensions on each anniversary of October 7^th. Mr. Kinder, at his initiative, accepted an annual salary of $1 to demonstrate his belief in Kinder Morgan Energy Partners, L.P.’s and Kinder Morgan, Inc.’s long term viability. Mr. Kinder continues to accept an annual salary of $1, and he receives no other compensation. Mr. Kinder’s employment agreement is extended annually at the request of Kinder Morgan, Inc.’s Board of Directors.


Item 11. Executive Compensation. (continued)	KMR Form 10-K

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

Common Unit Option Plan. Pursuant to Kinder Morgan Energy Partners, L.P. Common Unit Option Plan, key personnel are eligible to receive grants of options to acquire common units. The total number of common units authorized under the option plan is 500,000. None of the options granted under the option plan may be “incentive stock options” under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. Our compensation committee administers the option plan, and the plan has a termination date of March 5, 2008. Our compensation committee will determine the duration and vesting of the options to employees at the time of grant, and no individual employee may be granted options for more than 20,000 common units in any year. The option plan also granted to each of our non-employee directors an option to purchase 10,000 common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date.

For the year ended December 31, 2006, no options to purchase common units were granted to or exercised by any of our executive officers, and as of December 31, 2006, none of our executive officers owned unexercised common unit options. For the year ended December 31, 2006, no options to purchase common units were granted to our non-employee directors; however, one non-employee director held and exercised 10,000 common unit options during 2006. As of December 31, 2006, no options to purchase common units were outstanding under the plan.

Summary Compensation Table

The following table shows compensation paid for services rendered to us during fiscal year 2006 by (i) our principal executive officer, (ii) our principal financial officer, (iii) the three most highly compensated executive officers serving at fiscal year end, (iv) our three other highest ranking executive officers (collectively referred to as the “named executive officers”):


						(1)		(2)		(3)			(4)		(5)
Name and Principal Position	Year	Salary		Bonus		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation			Change in Pension Value		All Other Compensation		Total
Richard D. Kinder	2006	$	1	$	-	$	-	$	-		$	-	$	-	$	-	$	1
Director, Chairman and
Chief Executive Officer

Kimberly A. Dang	2006		200,000		-		139,296		37,023			270,000		6,968		46,253		699,540
Vice President and
Chief Financial Officer

Jeffrey R. Armstrong	2006		200,000		-		412,467		-			450,000		7,726		132,878		1,203,071
Vice President (President, Terminals)

Steven J. Kean	2006		200,000		-		1,591,192		147,943			-		7,422		284,919		2,231,476
Executive Vice President and Chief Operating Officer

David D. Kinder	2006		200,000		-		235,207		63,586			315,000		7,337		164,630		985,760
Vice President Corporate Development and Treasurer

Joseph Listengart	2006		200,000		-		721,817		-			-		7,835		224,753		1,154,405
Vice President, General Counsel and Secretary

Scott E. Parker	2006		200,000		350,000		881,317		29,490			500,000		8,735		164,630		2,134,172
Vice President (President, Natural Gas Pipelines)

C. Park Shaper	2006		200,000		-		1,134,283		24,952			-		7,835		348,542		1,715,612
Director and President


Item 11. Executive Compensation. (continued)	KMR Form 10-K

None of the restricted Kinder Morgan, Inc. stock awards were granted in 2006. Table amounts only represent the calendar year 2006 expense attributable to Kinder Morgan, Inc. restricted stock awarded in 2003, 2004 and 2005, and these awards were reflected in compensation tables previously filed by us with the Securities and Exchange Commission. The restricted shares were awarded according to the provisions of the Kinder Morgan, Inc. Stock Plan, and the computed value earned equaled the SFAS No. 123R expense accumulated during the 2006 calendar year. For grants of restricted stock, we take the value of the award at time of grant and accrue the expense over the vesting period according to SFAS No. 123R. For grants made July 16, 2003—Kinder Morgan, Inc. closing price was $53.80, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant. For grants made July 20, 2004—Kinder Morgan, Inc. closing price was $60.79, fifty percent of the shares vest on the third anniversary after the date of grant and the remaining fifty percent of the shares vest on the fifth anniversary after the date of grant. For grants made July 20, 2005—Kinder Morgan, Inc. closing price was $89.48, twenty-five percent of the shares in each grant vest on the third anniversary after the date of grant and the remaining seventy-five percent of the shares in each grant vest on the fifth anniversary after the date of grant.

None of the options to purchase Kinder Morgan, Inc. shares were granted in 2006. Table amounts only represent the calendar year 2006 expense attributable to options to purchase Kinder Morgan, Inc. shares granted in 2002 and 2003, and these awards were reflected in compensation tables previously filed by us with the Securities and Exchange Commission. The options were granted according to the provisions of the Kinder Morgan, Inc. Stock Plan, and the computed value earned equaled the SFAS No. 123R expense accumulated on unvested options during the 2006 calendar year. For options granted in 2002—volatility of 0.3912 using a 6 year term, 4.01% five year risk free interest rate return, and a 0.71% expected annual dividend rate. For options granted in 2003—volatility of 0.3853 using a 6.25 year term, 3.37% treasury strip quote at time of grant, and a 2.973% expected annual dividend rate.

Represents amounts paid according to the provisions of the Kinder Morgan, Inc. Annual Incentive Plan—except in the case of Mr. Parker, where $500,000 was paid under the plan and $350,000 was paid outside of the plan. Amounts were earned in 2006 but paid in 2007.

⁴

Represents the 2006 change in the actuarial present value of accumulated defined pension benefit (including unvested benefits) according to the provisions of Kinder Morgan, Inc.’s Cash Balance Retirement Plan.

⁵

Amounts represent value of contributions to the Kinder Morgan Savings Plan (a 401(k) plan), value of group-term life insurance exceeding $50,000, taxable parking subsidy and dividends paid on unvested restricted stock awards. For each individual excluding Mr. Richard D. Kinder, amounts include $10,000 representing the value of contributions to the Kinder Morgan Savings Plan. Amounts representing the value of dividends paid on unvested restricted stock awards are as follows: for Ms. Dang $35,875; for Mr. Armstrong $122,500; for Mr. Kean $273,000; for Mr. David D. Kinder $69,563; for Mr. Listengart $214,375; for Mr. Parker $154,000; and for Mr. Shaper $336,875.

The following supplemental compensation table shows compensation details on the value of all non-guaranteed and non-discretionary incentive awards granted during 2006 to our named executive officers. The table includes grant awards made during 2006 and discloses estimated future payouts for both equity and non-equity incentive plans.

Grants of Plan-Based Awards


	Estimated Future Payouts Under Non-Equity Incentive Plan Awards¹
Name	Threshold		Target		Maximum
Richard D. Kinder	$	-	$	-	$	-
Kimberly A. Dang		500,000		1,000,000		1,500,000
Jeffrey R. Armstrong		500,000		1,000,000		1,500,000
Steven J. Kean		750,000		1,500,000		2,000,000
David D. Kinder		500,000		1,000,000		1,500,000
Joseph Listengart		500,000		1,000,000		1,500,000
Scott E. Parker		500,000		1,000,000		1,500,000
C. Park Shaper		750,000		1,500,000		2,000,000

__________

Represents grants under the Kinder Morgan, Inc. Annual Incentive Plan for 2006. See “Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash Incentive)” for a discussion of these awards.

The following tables set forth certain information at December 31, 2006 with respect to all outstanding Kinder Morgan, Inc. equity awards granted to our named executive officers.


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Outstanding Kinder Morgan, Inc. Equity Awards at 2006 Year-End


	Option Awards									Stock Awards
	No. of Shares Underlying Unexercised Options				Option Exercise				Option Expiration	No. of Shares that Have Not		Market Value of Shares that
Name	Exercisable		Unexercisable		Price				Date	Vested¹		Have Not Vested²
Richard D. Kinder		-		-		$	-		-		-		$	-
Kimberly A. Dang		10,250		-			56.99		Jan. 16, 2012		8,000			846,000
		10,000		-			39.12		July 17, 2012		-			-
		4,500		-			53.80		July 16, 2010		-			-
Jeffrey R. Armstrong		22,000		-			53.20	Mar. 30, 2011			30,000			3,172,500
Steven J. Kean		12,500		-			56.99		Jan. 16, 2012		78,000			8,248,500
		13,500		-			39.12		July 12, 2012		-			-
		10,000		-			53.80		July 16, 2010		-			-
David D. Kinder		12,500		-			49.875		Jan. 17, 2011		15,750			1,665,563
		100		-			49.875		Jan. 17, 2011		-			-
		8,000		-			39.12		July 12, 2012		-			-
Joseph Listengart		50,000		-			23.8125		Oct. 8, 2009		52,500			5,551,875
		6,300		-			49.875		Jan. 17, 2011		-			-
Scott E. Parker		10,000		-			53.80		July 16, 2010		44,000			4,653,000
C. Park Shaper		95,000		-			24.75		Jan. 20, 2010		82,500			8,724,375
		25,000		-			49.875		Jan. 17, 2011		-			-
		100,000		-			56.99		Jan. 16, 2012		-			-

__________

For Ms. Dang, 2,000 shares vest July 20, 2007, 1,500 shares vest July 20, 2009, and 4,500 shares vest July 20, 2010; for Mr. Armstrong 30,000 shares vest July 16, 2008; for Mr. Kean 4,000 shares vest July 20, 2007, 17,500 shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and 52,500 shares vest July 20, 2010; for Mr. David D. Kinder 11,250 shares vest July 16, 2008, and 4,500 shares vest July 20, 2010; for Mr. Listengart 52,500 shares vest July 16, 2008; for Mr. Parker 4,000 shares vest July 20, 2007, 9,000 shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and 27,000 shares vest July 20, 2010; and for Mr. Shaper 82,500 shares vest July 16, 2008. Upon closing of the proposed merger agreement providing for the acquisition of KMI by investors, including Mr. Richard D. Kinder and other senior members of KMI management, all restricted stock vesting dates would be accelerated.

Calculated on the basis of the fair market value of the underlying shares at December 31, 2006 ($105.75).

The following tables set forth certain information for the fiscal year ended December 31, 2006 with respect to all outstanding Kinder Morgan, Inc. equity awards vested to our named executive officers during 2006 and all exercises of Kinder Morgan, Inc. stock options during 2006.

Kinder Morgan, Inc. Option Exercises and Kinder Morgan, Inc. Stock Vested in 2006


	Option Awards					Stock Awards
Name	Shares Acquired on Exercise		Value Realized on Exercise¹			Shares Acquired on Vesting		Value Realized on Vesting²
Richard D. Kinder		-		$	-		-	$	-
Kimberly A. Dang		-			-		-		-
Jeffrey R. Armstrong		10,000			522,642		11,000		1,098,980
Steven J. Kean		11,500			757,165		5,000		483,850
David D. Kinder		-			-		4,000		399,193
Joseph Listengart		-			-		20,000		1,991,925
Scott E. Parker		-			-		625		60,481
C. Park Shaper		-			-		30,000		2,991,925

__________

Calculated on the basis of the fair market value of the underlying shares at exercise date, minus the exercise price.

Calculated on the basis of the fair market value of underlying shares at the vesting date.

Director Compensation

Compensation Committee Interlocks and Insider Participation. Kinder Morgan Management, LLC’s compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation


Item 11. Executive Compensation. (continued)	KMR Form 10-K

decisions regarding our and Kinder Morgan G.P., Inc.’s executive officers. Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive officers of Kinder Morgan Management, LLC, participate in the deliberations of our compensation committee concerning executive officer compensation. None of the members of our compensation committee is or has been one of our officers or employees, and none of our executive officers served during 2006 on a board of directors of another entity which has employed any of the members of our compensation committee.

Directors Fees. Beginning in 2005, Kinder Morgan Energy Partners, L.P.’s Common Unit Compensation Plan for Non-Employee Directors, as discussed following, served as compensation for each of our three non-employee directors. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Our directors who are also employees of Kinder Morgan, Inc. (Messrs. Richard D. Kinder and C. Park Shaper) do not receive compensation in their capacity as directors.

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

The plan recognizes that the compensation to be paid to each non-employee director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. Each election will be generally at or around the first board meeting in January of each calendar year and will be effective for the entire calendar year. The election for 2006 was made effective January 17, 2006, and the election for 2007 was made effective January 16, 2007. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000.

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

The number of common units to be issued to a non-employee director electing to receive the cash compensation in the form of common units will equal the amount of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the day the cash compensation is awarded (such price, the fair market value), rounded down to the nearest 50 common units. The common units will be issuable as specified in the Common Unit Compensation Agreement. A non-employee director electing to receive the cash compensation in the form of common units will receive cash equal to the difference between (i) the cash compensation awarded to such non-employee director and (ii) the number of common units to be issued to such non-employee director multiplied by the fair market value of a common unit. This cash payment will be payable in four equal installments generally around March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded.

On January 17, 2006, each of our three non-employee directors was awarded cash compensation of $160,000 for board service during 2006. Effective January 17, 2006, each non-employee director elected to receive cash compensation of $87,780 in the form of Kinder Morgan Energy Partners, L.P. common units and was issued 1,750 common units pursuant to the plan and its agreements (based on the $50.16 closing market price of Kinder Morgan Energy Partners, L.P. common units on January 17, 2006, as reported on the New York Stock Exchange). The remaining $72,220 cash compensation was paid to each of the non-employee directors as described above. No other compensation was paid to the non-employee directors during 2006.

On January 17, 2007, each of our three non-employee directors was awarded cash compensation of $160,000 for board service during 2007. Effective January 17, 2007, each non-employee director elected to receive certain amounts of cash compensation in the form of Kinder Morgan Energy Partners, L.P. common units and each was issued common units pursuant to the plan and its agreements (based on the $48.44 closing market price of Kinder Morgan Energy Partners, L.P.


Item 11. Executive Compensation. (continued)	KMR Form 10-K

common units on January 17, 2007, as reported on the New York Stock Exchange). Mr. Gaylord elected to receive cash compensation of $95,911.20 in the form of Kinder Morgan Energy Partners, L.P. common units and was issued 1,980 common units; Mr. Waughtal elected to receive cash compensation of $159,852.00 in the form of Kinder Morgan Energy Partners, L.P. common units and was issued 3,300 common units; and Mr. Hultquist elected to receive cash compensation of $96,880.00 in the form of Kinder Morgan Energy Partners, L.P. common units and was issued 2,000 common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid to each of the non-employee directors as described above, and no other compensation will be paid to the non-employee directors during 2007.

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

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

On April 1, 2003, the date of adoption of the plan, each of our three non-employee directors was granted 7,500 unit appreciation rights. In addition, 10,000 unit appreciation rights were granted to each of our three non-employee directors on January 21, 2004, at the first meeting of the board in 2004. During the first board meeting of 2005, the plan was terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors; however, all unexercised awards made under the plan remain outstanding. No unit appreciation rights were exercised during 2006, and as of December 31, 2006, 52,500 unit appreciation rights had been granted, vested and remained outstanding.

The following table discloses the compensation earned by each of our three non-employee directors for board service during 2006. In addition, directors are reimbursed for reasonable expenses in connection with board meetings. Our directors who are also employees of Kinder Morgan, Inc. do not receive compensation in their capacity as directors.

Non-Employee Director Compensation for Fiscal Year 2006


Name	Fees Earned or Paid in Cash			Common Unit Awards¹			All Other Compensation²			Total
Edward O. Gaylord		$	72,220		$	87,780		$	3,418	163,418
Gary L. Hultquist			72,220			87,780			3,418	163,418
Perry M. Waughtal			72,220			87,780			3,418	163,418

__________

Represents the value of cash compensation received in the form of Kinder Morgan Energy Partners, L.P. common units according to the provisions of Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. Value computed as the number of common units elected to be received in lieu of cash (1,750 on January 17, 2006) times the closing price on date of election ($50.16 at January 17, 2006).

For each, represents the value of common unit appreciation rights earned during 2006 according to the provisions of Kinder Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan for Non-Employee Directors. For grants of common unit appreciation rights, compensation cost is determined according to the provisions of SFAS No.123R—for each common unit appreciation right, equal to the increase in value of each common unit over its grant-date fair value. Value of $600 computed as the number of common unit appreciation rights increasing in value during 2006 (7,500) times the increase in common unit closing price from December 31, 2005 to December 31, 2006 ($0.08; equal to $47.90 at December 31, 2006 less $47.82 at December 31, 2005). Also for each, includes $2,818 for distributions paid on unvested common units awarded according to the provisions of Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors.


Item 11. Executive Compensation. (continued)	KMR Form 10-K

Compensation Committee Report

Throughout fiscal 2006, the compensation committee of our board of directors was comprised of three directors, each of which our board of directors has determined meets the criteria for independence under our governance guidelines and the New York Stock Exchange rules.

The compensation

committee

has discussed and reviewed the above Compensation Discussion and Analysis for fiscal year 2006 with management. Based on this review and discussion, the compensation committee recommended to our board of directors that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for the fiscal year 2006.

Compensation Committee:
Edward O. Gaylord
Gary L. Hultquist
Perry M. Waughtal


	KMR Form 10-K

Item 12.

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

The following table sets forth information as of January 31, 2007, regarding (a) the beneficial ownership of (i) Kinder Morgan Energy Partners, L.P.’s common and Class B units, (ii) our shares and (iii) the common stock of Kinder Morgan, Inc., the parent company of Kinder Morgan G.P., Inc., by all our directors and those of Kinder Morgan G.P., Inc., by each of the named executive officers and by all our directors and executive officers as a group and (b) the beneficial ownership of Kinder Morgan Energy Partners, L.P.’s common and Class B units or our shares by all persons known by us to own beneficially at least 5% of Kinder Morgan Energy Partners, L.P.’s common and Class B units and our shares. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002.

Amount and Nature of Beneficial Ownership¹


	Kinder Morgan Energy Partners, L.P.						Kinder Morgan
							Management,			Kinder Morgan, Inc.
	Common Units			Class B Units			LLC Shares			Voting Stock
	Number of Units²	Percent of Class		Number of Units³	Percent of Class		Number of Shares⁴	Percent of Class		Number of Shares⁵	Percent of Class
	______________________________________________	______________________________________		_________________________________________	______________________________________		____________________________________________________	______________________________________		_________________________________________________	______________________________________
Richard D. Kinder⁶	315,979	*		-	-		59,910	*		24,000,000	17.90	%
C. Park Shaper⁷	4,000	*		-	-		2,913	*		352,070	*
Edward O. Gaylord⁸	38,480	*		-	-		-	-		2,000	*
Gary L. Hultquist⁹	16,500	*		-	-		-	-		500	-
Perry M. Waughtal¹⁰	44,100	*		-	-		43,243	*		70,030	*
Steven J. Kean¹¹	-	-		-	-		-	-		124,754	*
Joseph Listengart¹²	4,198	*		-	-		-	-		140,368	*
Scott E. Parker¹³	-	-		-	-		-	-		55,431	*
Kimberly A. Dang¹⁴	121	*		-	-		412	*		33,915	*
David D. Kinder¹⁵	2,186	*		-	-		1,408	*		42,307	*
Jeffrey R. Armstrong¹⁶	1,093	*		-	-		-	*		64,417	*
Directors and Executive
Officers as a group (14
persons)¹⁷	436,657	*		-	-		111,174	*		25,101,200	18.61	%
Kinder Morgan, Inc.¹⁸	14,355,735	8.90	%	5,313,400	100.00	%	9,676,909	15.53	%	-	-
Kayne Anderson Capital
Advisors, L.P. ¹⁹	-	-		-	-		6,250,520	10.79	%	-	-
OppenheimerFunds, Inc.²⁰	-	-		-	-		5,230,737	8.40	%	-	-
Tortoise Capital Advisors, L.L.C.²¹	-	-		-	-		4,047,052	6.50%		-	-

______________

*Less than 1%.

Except as noted otherwise, all units, our shares and Kinder Morgan, Inc. shares involve sole voting power and sole investment power. For Kinder Morgan Management, LLC, see note (4). On January 18, 2005, Kinder Morgan Management, LLC’s board of directors initiated a rule requiring each director to own a minimum of 10,000 common units, Kinder Morgan Management, LLC shares, or a combination thereof. If a director does not already own the minimum number of required securities, the director will have six years to acquire such securities.

As of January 31, 2007, Kinder Morgan Energy Partners, L.P. had 162,823,583 common units issued and outstanding.

As of January 31, 2007, Kinder Morgan Energy Partners, L.P. had 5,313,400 Class B units issued and outstanding.

⁴

Represent the limited liability company shares of Kinder Morgan Management, LLC. As of January 31, 2007, there were 62,301,674 issued and outstanding Kinder Morgan Management, LLC shares, including two voting shares owned by Kinder Morgan G.P., Inc. In all cases, Kinder Morgan Energy Partners, L.P.’s i-units will be voted in proportion to the affirmative and negative votes, abstentions and non-votes of owners of Kinder Morgan Management, LLC shares. Through the provisions in Kinder Morgan Energy Partners, L.P.’s partnership agreement and Kinder Morgan Management, LLC’s limited liability company agreement, the number of outstanding Kinder Morgan Management, LLC shares, including voting shares owned by Kinder Morgan G.P., Inc., and the number of Kinder Morgan Energy Partners, L.P.’s i-units will at all times be equal.

⁵

As of January 31, 2007, Kinder Morgan, Inc. had a total of 134,188,793 shares of issued and outstanding voting common stock, which excludes 15,023,351 shares held in treasury.

⁶

Includes (a) 7,879 common units owned by Mr. Kinder’s spouse, (b) 5,173 Kinder Morgan, Inc. shares held by Mr. Kinder’s spouse and (c) 250 Kinder Morgan, Inc. shares held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares.

⁷

Includes options to purchase 220,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 82,500 shares of restricted Kinder Morgan, Inc. stock.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters. (continued)

KMR Form 10-K

⁸

Includes 1,980 restricted common units.

⁹

Includes 2,000 restricted common units.

¹⁰

Includes 3,300 restricted common units.

¹¹

Includes options to purchase 36,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and 78,000 shares of restricted Kinder Morgan, Inc. stock.

¹²

Includes options to purchase 56,300 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 52,500 shares of restricted Kinder Morgan, Inc. stock.

¹³

Includes options to purchase 10,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 44,000 shares of restricted Kinder Morgan, Inc. stock.

¹⁴

Includes options to purchase 24,750 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 8,000 shares of restricted Kinder Morgan, Inc. stock.

¹⁵

Includes 1,211 Kinder Morgan Energy Partners, L.P. common units owned by Mr. Kinder’s spouse, 240 Kinder Morgan Management, LLC shares purchased in November 2004 for Mr. Kinder’s son (and nominal share distributions thereon), options to purchase 20,600 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 15,750 shares of restricted Kinder Morgan, Inc. stock. Mr. Kinder’s son holds 250 shares of Kinder Morgan, Inc. stock, which shares are not included in the number of shares Mr. Kinder beneficially owns. Mr. Kinder disclaims any and all beneficial ownership in the Kinder Morgan Energy Partners, L.P. common units owned by his wife, and the Kinder Morgan Management, LLC shares and the Kinder Morgan, Inc. stock owned by his sons.

¹⁶

Includes options to purchase 22,000 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 30,000 shares of restricted Kinder Morgan, Inc. stock.

¹⁷

Includes options to purchase 458,050 Kinder Morgan, Inc. shares exercisable within 60 days of January 31, 2007, and includes 7,280 restricted Kinder Morgan Energy Partners, L.P. common units and 400,750 shares of restricted Kinder Morgan, Inc. stock.

¹⁸

Includes common units owned by Kinder Morgan, Inc. and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.

¹⁹

As reported on the Schedule 13G/A filed February 5, 2007 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reported that in regard to Kinder Morgan Management, LLC shares, it had sole voting power over 0 shares, shared voting power over 6,978,859 shares, sole disposition power over 0 shares and shared disposition power over 6,978,859 shares. Mr. Kayne reports that in regard to Kinder Morgan Management, LLC shares, he had sole voting power over 1,060 shares, shared voting power over 6,978,859 shares, sole disposition power over 1,060 shares and shared disposition power over 6,978,859 shares. Kayne Anderson Capital Advisors, L.P.’s and Richard A. Kayne’s address is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067.

²⁰

As reported on the Schedule 13G/A filed February 6, 2007 by OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund. OppenheimerFunds, Inc. reported that in regard to Kinder Morgan Management, LLC shares, it had sole voting power over 0 shares, shared voting power over 5,230,737 shares, sole disposition power over 0 shares and shared disposition power over 5,230,737 shares. Of those 5,230,737 Kinder Morgan Management, LLC shares, Oppenheimer Capital Income Fund had sole voting power over 0 shares, shared voting power over 3,657,500 shares, sole disposition power over 0 shares and shared disposition power over 3,657,500 shares. OppenheimerFunds, Inc.’s address is Two World Financial Center, 225 Liberty Street, 11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund’s address is 6803 South Tucson Way, Centennial, Colorado 80112.

²¹

As reported on the Schedule 13G/A filed February 13, 2007 by Tortoise Capital Advisors, L.L.C. Tortoise Capital Advisors, L.L.C. reported that in regard to Kinder Morgan Management, LLC shares, it had sole voting power over 0 shares, shared voting power over 3,960,233 shares, sole disposition power over 0 shares and shared disposition power over 4,047,052 shares. Tortoise Capital Advisors, L.L.C.’s address is 10801 Mastin Blvd., Suite 222, Overland Park, Kansas 66210.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters. (continued)

KMR Form 10-K

Equity Compensation Plan Information

The following table sets forth information regarding Kinder Morgan Energy Partners, L.P.’s equity compensation plans as of December 31, 2006. Specifically, the table provides information regarding Kinder Morgan Energy Partners, L.P.’s Common Unit Option Plan and Common Unit Compensation Plan for Non-Employee Directors, both described in Item 11., “Executive Compensation.”


	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Plan category	(a)		(b)		(c)
Equity compensation plans approved by security holders		-		-		-

Equity compensation plans not approved by security holders		-		-		149,100

Total		-		-		149,100

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

General and Administrative Expenses

KMGP Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides employees and Kinder Morgan Services LLC, our wholly owned subsidiary, provides centralized payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.’s 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 all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group, and the members of the Group reimburse Kinder Morgan Services LLC for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., 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 its limited partnership agreement, Kinder Morgan Energy Partners, L.P. provides reimbursement for its share of these administrative costs and such reimbursements will be accounted for as described above. Additionally, Kinder Morgan Energy Partners, L.P. reimburses us with respect to costs incurred or allocated to us in accordance with Kinder Morgan Energy Partners, L.P.’s limited partnership agreement, the delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., us and others, and our limited liability company agreement.

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

Kinder Morgan Energy Partners, L.P. Distributions

Kinder Morgan G.P., Inc.

Kinder Morgan G.P., Inc. serves as the sole general partner of Kinder Morgan Energy Partners, L.P. Pursuant to their partnership agreements, Kinder Morgan G.P., Inc.’s general partner interests represent a 1% ownership interest in Kinder Morgan Energy Partners, L.P., and a direct 1.0101% ownership interest in each of Kinder Morgan Energy Partners, L.P.’s five operating partnerships. Collectively, Kinder Morgan G.P., Inc. owns an effective 2% interest in the operating partnerships, excluding incentive distributions rights as follows:

its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of Kinder Morgan Energy Partners, L.P.); and

its 0.9899% ownership interest indirectly owned via its 1% ownership interest in Kinder Morgan Energy Partners, L.P.

Item 13.

Certain Relationships and Related Transactions. (continued)

KMR Form 10-K

As of December 31, 2006, Kinder Morgan G.P., Inc. owned 1,724,000 common units, representing approximately 0.75% of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner units.

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

Kinder Morgan G.P., Inc. is granted discretion by Kinder Morgan Energy Partners, L.P.’s partnership agreement, which discretion has been delegated to us, subject to the approval of Kinder Morgan G.P., Inc. in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When we determine Kinder Morgan Energy Partners, L.P.’s quarterly distributions, we consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Kinder Morgan G.P., Inc. and owners of Kinder Morgan Energy Partners, L.P.’s common units and Class B units receive distributions in cash, while we, the sole owner of Kinder Morgan Energy Partners, L.P.’s i-units, receive distributions in additional i-units. Kinder Morgan Energy Partners, L.P. does not distribute cash to i-unit owners but retains the cash for use in its business. However, the cash equivalent of distributions of i-units is treated as if it had actually been distributed for purposes of determining the distributions to Kinder Morgan G.P., Inc. Each time Kinder Morgan Energy Partners, L.P. makes a distribution, the number of i-units owned by us and the percentage of Kinder Morgan Energy Partners, L.P.’s total units owned by us increase automatically under the provisions of Kinder Morgan Energy Partners, L.P.’s partnership agreement.

Kinder Morgan, Inc.

Kinder Morgan, Inc., through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of Kinder Morgan G.P., Inc. At December 31, 2006, Kinder Morgan, Inc. directly owned 8,838,095 common units, indirectly owned 5,313,400 Class B units and 5,517,640 common units owned by its consolidated affiliates, including Kinder Morgan G.P., Inc., and owned 10,305,553 of our shares, representing an indirect ownership interest of 10,305,553 Kinder Morgan Energy Partners, L.P.’s i-units. Together, these units represent approximately 13.0% of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner units. Including both its general and limited partner interests in Kinder Morgan Energy Partners, L.P., at the 2006 distribution level, Kinder Morgan, Inc. received approximately 49% of all quarterly distributions from Kinder Morgan Energy Partners, L.P., of which approximately 42% is attributable to its general partner interest and 7% is attributable to its limited partner interest. The actual level of distributions Kinder Morgan, Inc. will receive in the future will vary with the level of distributions to the limited partners determined in accordance with Kinder Morgan Energy Partners, L.P.’s partnership agreement.

Kinder Morgan Management, LLC

We, as Kinder Morgan G.P., Inc.’s delegate, are the sole owner of Kinder Morgan Energy Partners, L.P.’s 62,301,676 i-units.

Operations

Kinder Morgan, Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners, L.P. the assets comprising Kinder Morgan Energy Partners, L.P.’s Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of Kinder Morgan, Inc., operates Trailblazer Pipeline Company’s assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to Natural Gas Pipeline Company of America’s operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for capital expenditures. Natural Gas Pipeline Company of America does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company’s assets.

The remaining assets comprising Kinder Morgan Energy Partners, L.P.’s Natural Gas Pipelines business segment as well as Kinder Morgan Energy Partners, L.P.’s North System and Cypress Pipeline, which are part of Kinder Morgan Energy Partners, L.P.’s Products Pipelines business segment, are operated under agreements between Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. Pursuant to the applicable underlying agreements, Kinder Morgan Energy Partners, L.P. pays Kinder Morgan, Inc. either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. The amounts paid to Kinder Morgan, Inc. for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $1.0 million of fixed costs and $37.9 million of actual costs incurred for 2006, $5.5 million of fixed costs and $24.2 million of actual costs incurred for 2005, and $8.8 million of fixed costs and $13.1 million of actual costs incurred for 2004.

Item 13.

Certain Relationships and Related Transactions. (continued)

KMR Form 10-K

Kinder Morgan Energy Partners, L.P. believes the amounts paid to Kinder Morgan, Inc. for the services they provided each year fairly reflect the value of the services performed. However, due to the nature of the allocations, these reimbursements may not exactly match the actual time and overhead spent. Kinder Morgan Energy Partners, L.P. believes the fixed amounts that were agreed upon at the time the contracts were entered into were reasonable estimates of the corporate general and administrative expenses to be incurred by Kinder Morgan, Inc. and its subsidiaries in performing such services. Kinder Morgan Energy Partners, L.P. also reimburses Kinder Morgan, Inc. and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets.

Kinder Morgan, Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners, L.P. the power plant Kinder Morgan Energy Partners, L.P. constructed at the SACROC oil field unit, located in the Permian Basin area of West Texas. Kinder Morgan Production Company, a subsidiary of one of Kinder Morgan Energy Partners, L.P.’s operating limited partnerships, completed construction of the power plant in June 2005 at an approximate cost of $76 million. The power plant provides approximately half of SACROC’s current electricity needs.

Kinder Morgan Power Company, a subsidiary of Kinder Morgan, Inc., operates and maintains the power plant under a five-year contract expiring in June 2010. Pursuant to the contract, Kinder Morgan, Inc. incurs the costs and expenses related to operating and maintaining the power plant for the production of electrical energy at the SACROC field. Such costs include supervisory personnel and qualified operating and maintenance personnel in sufficient numbers to accomplish the services provided in accordance with good engineering, operating and maintenance practices. Kinder Morgan Production Company fully reimburses Kinder Morgan, Inc.’s expenses, including all agreed-upon labor costs, and also pays to Kinder Morgan, Inc. an operating fee of $20,000 per month.

In addition, Kinder Morgan Production Company is responsible for processing and directly paying invoices for fuels utilized by the plant. Other materials, including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia and any catalyst are purchased by Kinder Morgan, Inc. and invoiced monthly as provided by the contract, if not paid directly by Kinder Morgan Production Company. The amount paid to Kinder Morgan, Inc. in 2006 and 2005 for operating and maintaining the power plant was $2.9 million and $0.8 million, respectively. Kinder Morgan Energy Partners, L.P. estimates the total reimbursement to be paid to Kinder Morgan, Inc. for operating and maintaining the plant for 2007 will be approximately $3.3 million. Furthermore, Kinder Morgan Energy Partners, L.P. believes the amounts paid to Kinder Morgan, Inc. for the services they provide each year fairly reflect the value of the services performed.

KM Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and wholly-owned subsidiary of Kinder Morgan, Inc. KMIL was formed during the second quarter of 2005 as a Class 2 Bermuda insurance company, the sole business of which is to issue policies for Kinder Morgan, Inc. and Kinder Morgan Energy Partners, L.P. to secure the deductible portion of Kinder Morgan Energy Partners, L.P.’s workers compensation, automobile liability, and general liability policies placed in the commercial insurance market. Kinder Morgan Energy Partners, L.P. accrues for the cost of insurance, which is included in the related party general and administrative expenses and which totaled approximately $5.8 million in 2006.

From time to time in the ordinary course of business, Kinder Morgan Energy Partners, L.P. buys and sells pipeline and related services from Kinder Morgan, Inc. and its subsidiaries. Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with Kinder Morgan Energy Partners, L.P.’s policies governing such transactions.

Certain of Kinder Morgan Energy Partners, L.P.’s business activities expose Kinder Morgan Energy Partners, L.P. to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. Kinder Morgan Energy Partners, L.P. also has exposure to interest rate risk as a result of the issuance of its fixed rate debt obligations. Pursuant to Kinder Morgan Energy Partners, L.P.’s management’s approved risk management policy, Kinder Morgan Energy Partners, L.P. uses derivative contracts to hedge or reduce our exposure to these risks and protect its profit margins.

Kinder Morgan Energy Partners, L.P.’s risk management policies prohibit it from engaging in speculative trading. Kinder Morgan Energy Partners, L.P.’s commodity-related risk management activities are monitored by its risk management committee, which is a separately designated standing committee whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. Kinder Morgan Energy Partners, L.P.’s risk management committee is charged with the review and enforcement of its management’s risk management policy. The committee is comprised of 19 executive-level employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. whose job responsibilities involve operations exposed to commodity market risk and other external risks in the ordinary course of business. The committee is chaired by Kinder Morgan Energy Partners, L.P.’s President and is charged with the following three responsibilities:

establish and review risk limits consistent with Kinder Morgan Energy Partners, L.P.’s risk tolerance philosophy;

recommend to our audit committee any changes, modifications, or amendments to Kinder Morgan Energy Partners, L.P.’s risk management policy; and

Item 13.

Certain Relationships and Related Transactions. (continued)

KMR Form 10-K

address and resolve any other high-level risk management issues.

Other

Generally, we make all decisions relating to the management and control of Kinder Morgan Energy Partners, L.P.’s business. Kinder Morgan G.P., Inc. owns all of our voting securities and is our sole managing member. Kinder Morgan, Inc., through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of Kinder Morgan G.P., Inc. Certain conflicts of interest could arise as a result of the relationships among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan, Inc. and us. The directors and officers of Kinder Morgan, Inc. have fiduciary duties to manage Kinder Morgan, Inc., including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of Kinder Morgan, Inc. In general, we have a fiduciary duty to manage Kinder Morgan Energy Partners, L.P. in a manner beneficial to Kinder Morgan Energy Partners, L.P. unitholders. The partnership agreements for Kinder Morgan Energy Partners, L.P. and its operating partnerships contain provisions that allow us to take into account the interests of parties in addition to Kinder Morgan Energy Partners, L.P. in resolving conflicts of interest, thereby limiting our fiduciary duty to Kinder Morgan Energy Partners, L.P. unitholders, as well as provisions that may restrict the remedies available to Kinder Morgan Energy Partners, L.P. unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

The partnership agreements provide that in the absence of bad faith by us, the resolution of a conflict by us will not be a breach of any duties. The duty of the directors and officers of Kinder Morgan, Inc. to the shareholders of Kinder Morgan, Inc. may, therefore, come into conflict with our duties and the duties of our directors and officers to Kinder Morgan Energy Partners, L.P. unitholders. The audit committee of our board of directors will, at our request, review (and is one of the means for resolving) conflicts of interest that may arise between Kinder Morgan, Inc. or its subsidiaries, on the one hand, and Kinder Morgan Energy Partners, L.P., on the other hand.

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

Director Independence

Pursuant to a delegation of control agreement among Kinder Morgan Energy Partners, L.P., its general partner, us and others, we manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., except that we cannot take certain specified actions without the approval of Kinder Morgan Energy Partners, L.P.’s general partner. The limited partnership agreement of Kinder Morgan Energy Partners, L.P. provides for a general partner of the Partnership rather than a board of directors. Through the operation of Kinder Morgan Energy Partners, L.P.’s limited partnership agreement and the delegation of control agreement, our board of directors performs the functions of and is the equivalent of a board of directors of Kinder Morgan Energy Partners, L.P. Similarly, the standing committees of our board function as standing committees of the board of Kinder Morgan Energy Partners, L.P. Our board of directors is comprised of the same persons who comprise Kinder Morgan Energy Partners, L.P.’s general partner’s board of directors. References in this report to the board mean our board acting as the delegate of and as the board of directors of Kinder Morgan Energy Partners, L.P.’s general partner, and references to committees mean committees of the board acting as the delegate of and as the committees of the board of directors of Kinder Morgan Energy Partners, L.P.’s general partner.

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

If the director was an employee, or had an immediate family member who was an executive officer, of us or Kinder Morgan Energy Partners, L.P. or any of its affiliates, but the employment relationship ended more than three years prior to the date of determination (or, in the case of employment of a director as an interim chairman, interim chief executive officer or interim executive officer, such employment relationship ended by the date of determination);

Item 13.

Certain Relationships and Related Transactions. (continued)

KMR Form 10-K

If during any twelve month period within the three years prior to the determination the director received no more than, and has no immediate family member that received more than, $100,000 in direct compensation from Kinder Morgan Energy Partners, L.P. or its affiliates, other than (i) director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), (ii) compensation received by a director for former service as an interim chairman, interim chief executive officer or interim executive officer, and (iii) compensation received by an immediate family member for service as an employee (other than an executive officer);

If the director is at the date of determination a current employee, or has an immediate family member that is at the date of determination a current executive officer, of another company that has made payments to, or received payments from, Kinder Morgan Energy Partners, L.P. and its affiliates for property or services in an amount which, in each of the three fiscal years prior to the date of determination, was less than the greater of $1.0 million or 2% of such other company’s annual consolidated gross revenues. Contributions to tax-exempt organizations are not considered payments for purposes of this determination;

If the director is also a director, but is not an employee or executive officer, of Kinder Morgan Energy Partners, L.P.’s general partner or another affiliate or affiliates of us or Kinder Morgan Energy Partners, L.P., so long as such director is otherwise independent; and

If the director beneficially owns less than 10% of each class of voting securities of us, Kinder Morgan, Inc., Kinder Morgan Energy Partners, L.P. or its general partner.

The board has affirmatively determined that Messrs. Gaylord, Hultquist and Waughtal, who constitute a majority of the directors, are independent as described in our governance guidelines and the New York Stock Exchange rules. Each of them meets the standards above and has no other relationship with us. In conjunction with all regular quarterly and certain special board meetings, these three non-management directors also meet in executive session without members of management. In January 2007, Mr. Waughtal was elected for a one year term to serve as lead director to develop the agendas for and preside at these executive sessions of independent directors.

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

Item 14.

Principal Accounting Fees and Services.

The following sets forth fees billed for the audit and other services provided by PricewaterhouseCoopers LLP to us for the fiscal years ended December 31, 2006, and December 31, 2005:


	Year Ended December 31,
	2006			2005
	(In dollars)
Audit fees¹	$	180,000	$		189,000
Total	$	180,000	$		189,000

Includes fees for integrated audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements and reviews of documents filed with the Securities and Exchange Commission.

All services rendered by PricewaterhouseCoopers LLP are permissible under applicable laws and regulations, and were pre-approved by our Audit Committee, consistent with the Audit Committee’s charter, which requires the pre-approval of all audit and non-audit services. The Audit Committee’s primary purposes include the following:

monitor the integrity of our financial statements, financial reporting processes, systems of internal controls regarding finance, accounting and legal compliance and disclosure controls and procedures;

monitor our compliance with legal and regulatory requirements;

select, appoint, engage, oversee, retain, evaluate and terminate our external auditors, pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors, and establish the fees and other compensation to be paid to our external auditors;

monitor and evaluate the qualifications, independence and performance of our external auditors and internal auditing function; and

Item 14.

Principal Accounting Fees and Services. (continued)

KMR Form 10-K

establish procedures for the receipt, retention, response to and treatment of complaints, including confidential, anonymous submissions by our employees, regarding accounting, internal controls, disclosure or auditing matters, and provide an avenue of communication among our external auditors, management, the internal auditing function and our Board of Directors.

The Audit Committee has reviewed the external auditors’ fees for audit and non audit services for fiscal year 2006. The Audit Committee considered whether such non-audit services are compatible with maintaining the external auditors’ independence and has concluded that they are compatible at this time.

Furthermore, the audit committee will review the external auditors’ proposed audit scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, will regularly review with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and will, at least annually, use its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

the auditors’ internal quality-control procedures;

any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

the independence of the external auditors; and

the aggregate fees billed by our external auditors for each of the previous two fiscal years.

KMR Form 10-K

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) 1.

Financial Statements

Reference is made to the index of financial statements and supplementary data under Item 8 in Part II.

KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

We have no valuation or qualifying accounts subject to disclosure in Schedule II.

Exhibits

Exhibit

Number

Description

3.1

Form of Certificate of Formation of the Company (filed as Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein).

3.2

Second Amended and Restated Limited Liability Company Agreement of the Company (filed as Exhibit 4.2 to the Company’s Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).

4.1

Form of certificate representing shares of the Company (filed as Exhibit 4.3 to the Company’s Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).

4.2

Form of Purchase Provisions between the Company and Kinder Morgan, Inc. (included as Annex B to the Second Amended and Restated Limited Liability Company Agreement filed as Exhibit 4.2 to the Company’s Registration Statement on Form 8-A/A filed on July 24, 2002 and incorporated by reference herein).

4.3

Registration Rights Agreement dated May 18, 2001 among the Company, Kinder Morgan Energy Partners, L.P. and Kinder Morgan, Inc. (Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.1

Form of Tax Indemnity Agreement between the Company and Kinder Morgan, Inc. (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S-1 (Registration No. 333-55868) and incorporated by reference herein).

10.2

Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. June 30, 2001 Form 10-Q (Commission File No. 1-11234)).

10.3

Resignation and Non-Compete Agreement, dated as of July 21, 2004, between KMGP Services, Inc. and Michael C. Morgan (Exhibit 10.4 to Kinder Morgan Management, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).

21.1*

List of Subsidiaries.

23.1*

Consent of PricewaterhouseCoopers LLP.

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


Item 15. Exhibits and Financial Statement Schedules. (continued)	KMR Form 10-K

Exhibit

Number

Description

32.1*

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

__________

* Filed herewith.

KMR Form 10-K

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	KINDER MORGAN MANAGEMENT, LLC (Registrant)
	By	/s/ Kimberly A. Dang
		Kimberly A. Dang Vice President and Chief Financial Officer
Date: March 1, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities set forth below and as of the date set forth above.


/s/ Richard D. Kinder		Director, Chairman and Chief Executive Officer
Richard D. Kinder		(Principal Executive Officer)

/s/ Kimberly A. Dang		Vice President and Chief Financial Officer (Principal
Kimberly A. Dang		Financial Officer and Principal Accounting Officer)

/s/ Edward O. Gaylord		Director
Edward O. Gaylord

/s/ Gary L. Hultquist		Director
Gary L. Hultquist

/s/ C. Park Shaper		Director and President
C. Park Shaper

/s/ Perry M. Waughtal		Director
Perry M. Waughtal

Annex A

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

----------------------

Form 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-11234

Kinder Morgan Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware 76-0380342

(State or other jurisdiction of (I.R.S. Employer

incorporation or organization) Identification No.)

500 Dallas, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

----------------------

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

Title of each class Name of each exchange on which registered

Common Units New York Stock Exchange

Securities registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer,

as defined in Rule 405 of the Securities Act of 1933. Yes [X] No [ ]

Indicate by check mark if the registrant is not required to file reports

pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.

Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports

required to be filed by Section 13 or 15(d) of the Securities Exchange Act of

1934 during the preceding 12 months (or for such shorter period that the

registrant was required to file such reports), and (2) has been subject to such

filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item

405 of Regulation S-K is not contained herein, and will not be contained, to the

best of registrant's knowledge, in definitive proxy or information statements

incorporated by reference in Part III of this Form 10-K or any amendment to this

Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer,

an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of

the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated

filer [ ] Non-accelerated filer [ ]

<PAGE>

Indicate by check mark whether the registrant is a shell company (as

defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]

Aggregate market value of the voting and non-voting common equity held by

non-affiliates of the registrant, based on closing prices in the daily composite

list for transactions on the New York Stock Exchange on June 30, 2006 was

approximately $6,538,368,966. As of January 31, 2007, the registrant had

162,823,583 Common Units outstanding.

<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

Page

Number

------

PART I

Items 1 and 2. Business and Properties.................................... 4

General Development of Business........................... 4

Business Strategy........................................ 5

Recent Developments...................................... 6

Financial Information about Segments...................... 14

Narrative Description of Business......................... 14

Products Pipelines....................................... 14

Natural Gas Pipelines.................................... 22

CO2...................................................... 30

Terminals................................................ 34

Major Customers........................................... 39

Regulation................................................ 39

Environmental Matters..................................... 42

Other..................................................... 45

Financial Information about Geographic Areas.............. 45

Available Information..................................... 46

Item 1A. Risk Factors............................................... 46

Item 1B. Unresolved Staff Comments.................................. 53

Item 3. Legal Proceedings.......................................... 53

Item 4. Submission of Matters to a Vote of Security Holders........ 53

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder

Matters and Issuer Purchases of Equity Securities......... 54

Item 6. Selected Financial Data.................................... 55

Item 7. Management's Discussion and Analysis of Financial

Condition and Results of Operations....................... 57

Critical Accounting Policies and Estimates................ 57

Results of Operations..................................... 61

Liquidity and Capital Resources........................... 88

Recent Accounting Pronouncements.......................... 99

Information Regarding Forward-Looking Statements.......... 99

Item 7A. Quantitative and Qualitative Disclosures About

Market Risk............................................... 101

Energy Commodity Market Risk.............................. 101

Interest Rate Risk........................................ 103

Item 8. Financial Statements and Supplementary Data................ 104

Item 9. Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure........................ 104

Item 9A. Controls and Procedures.................................... 104

Item 9B. Other Information.......................................... 106

PART III

Item 10. Directors, Executive Officers and Corporate Governance..... 107

Directors and Executive Officers of our General

Partner and its Delegate.................................. 107

Corporate Governance...................................... 109

Section 16(a) Beneficial Ownership Reporting Compliance... 110

Item 11. Executive Compensation..................................... 110

Item 12. Security Ownership of Certain Beneficial Owners and

Management and Related Stockholder Matters................. 125

Item 13. Certain Relationships and Related Transactions, and

Director Independence...................................... 128

Item 14. Principal Accounting Fees and Services..................... 129

PART IV

Item 15. Exhibits and Financial Statement Schedules................. 131

Index to Financial Statements.............................. 134

Signatures................................................................ 241

<PAGE>

PART I

Items 1 and 2. Business and Properties.

In this report, unless the context requires otherwise, references to "we,"

"us," "our," "KMP" or the "Partnership" are intended to mean Kinder Morgan

Energy Partners, L.P., a Delaware limited partnership, our operating limited

partnerships and their subsidiaries. Our common units, which represent limited

partner interests in us, trade on the New York Stock Exchange under the symbol

"KMP." The address of our principal executive offices is 500 Dallas, Suite 1000,

Houston, Texas 77002, and our telephone number at this address is (713)

369-9000. You should read the following discussion and analysis in conjunction

with our consolidated financial statements included elsewhere in this report.

(a) General Development of Business

Kinder Morgan Energy Partners, L.P. is 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. We own or operate approximately 26,000 miles of pipelines and

approximately 150 terminals. Our pipelines transport more than two million

barrels per day of gasoline and other petroleum products and up to seven 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 are also

the leading independent provider of carbon dioxide for enhanced oil recovery

projects in the United States.

As of December 31, 2006, Kinder Morgan, Inc. and its consolidated

subsidiaries, referred to in this report as KMI, owned, through its general and

limited partner interests, an approximate 14.7% interest in us. KMI's common

stock trades on the New York Stock Exchange under the symbol "KMI," and KMI is

one of the largest energy transportation and storage companies in North America,

operating or owning an interest in, either for itself or on our behalf,

approximately 43,000 miles of pipelines and approximately 155 terminals. KMI and

its consolidated subsidiaries also distribute natural gas to approximately 1.1

million customers.

In addition to the distributions it receives from its limited and general

partner interests, KMI also receives an incentive distribution from us as a

result of its ownership of our general partner. This incentive distribution is

calculated in increments based on the amount by which quarterly distributions to

our unitholders exceed specified target levels as set forth in our partnership

agreement, reaching a maximum of 50% of distributions allocated to the general

partner for distributions above $0.23375 per limited partner unit per quarter.

Including both its general and limited partner interests in us, at the 2006

distribution level, KMI received approximately 49% of all quarterly "Available

Cash" distributions (as defined in our partnership agreement) from us, with

approximately 42% and 7% of all quarterly distributions from us attributable to

KMI's general partner and limited partner interests, respectively. The actual

level of distributions KMI will receive in the future will vary with the level

of distributions to our limited partners determined in accordance with our

partnership agreement.

In February 2001, Kinder Morgan Management, LLC, a Delaware limited

liability company referred to in this report as KMR, was formed. Our general

partner owns all of KMR's voting securities and, pursuant to a delegation of

control agreement, our general partner has delegated to KMR, to the fullest

extent permitted under Delaware law and our partnership agreement, all of its

power and authority to manage and control our business and affairs, except that

KMR cannot take certain specified actions without the approval of our general

partner. Under the delegation of control agreement, KMR, as the delegate of our

general partner, manages and controls our business and affairs and the business

and affairs of our operating limited partnerships and their subsidiaries.

Furthermore, in accordance with its limited liability company agreement, KMR's

activities are limited to being a limited partner in, and managing and

controlling the business and affairs of us, our operating limited partnerships

and their subsidiaries.

KMR's shares represent limited liability company interests and trade on the

New York Stock Exchange under the symbol "KMR." Since its inception, KMR has

used substantially all of the net proceeds received from the public offerings of

its shares to purchase i-units from us, thus becoming a limited partner in us.

The i-units are a separate class of limited partner interests in us and are

issued only to KMR. Under the terms of our partnership agreement, the i-units

are entitled to vote on all matters on which the common units are entitled to

vote.

<PAGE>

In general, our limited partner units, consisting of i-units, common units

and Class B units (the Class B units are similar to our common units except that

they are not eligible for trading on the New York Stock Exchange), will vote

together as a single class, with each i-unit, common unit and Class B unit

having one vote. We pay our quarterly distributions from operations and interim

capital transactions to our common and Class B unitholders in cash, and we pay

our quarterly distributions to KMR in additional i-units rather than in cash. As

of December 31, 2006, KMR, through its ownership of our i-units, owned

approximately 27.0% of all of our outstanding limited partner units.

On May 29, 2006, KMI announced that its board of directors had received a

proposal from investors led by Richard D. Kinder, Chairman and Chief Executive

Officer of KMI, to acquire all of the outstanding shares of KMI for $100 per

share in cash. The investors include members of senior management of KMI, most

of whom are also senior officers of our general partner and of KMR. KMI's board

of directors formed a special committee composed entirely of independent

directors to consider the proposal. On August 28, 2006, KMI entered into a

definitive merger agreement under which the investors would acquire all of KMI's

outstanding common stock (except for shares held by certain stockholders and

investors) for $107.50 per share in cash, without interest, and KMI's board of

directors, on the unanimous recommendation of the special committee, approved

the agreement and recommended that its stockholders approve the merger.

On December 19, 2006, KMI announced that its stockholders voted to approve

the proposed merger agreement providing for the acquisition of KMI by the

investors, which include: Richard D. Kinder, other senior members of KMI

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. On January 25,

2007, KMI announced that it 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 of KMI 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, KMI is working

diligently with the CPUC to try to expedite the matter and is hopeful that the

transaction can be closed in the first quarter of 2007. Upon closing of the

transaction, KMI's common stock will no longer be traded on the New York Stock

Exchange.

Business Strategy

The objective of our business strategy is to grow our portfolio of

businesses by:

o focusing on stable, fee-based energy transportation and storage assets

that are core to the energy infrastructure of growing markets within

the United States;

o increasing utilization of our existing assets while controlling costs,

operating safely, and employing environmentally sound operating

practices;

o leveraging economies of scale from incremental acquisitions and

expansions of assets that fit within our strategy and are accretive to

cash flow and earnings; and

o maximizing the benefits of our financial structure to create and

return value to our unitholders.

Primarily, our business model consists of owning and/or operating a solid

asset base designed to generate stable, fee-based income and distributable cash

flow that together provide overall long-term value to our unitholders. We own

and manage a diversified portfolio of energy transportation and storage assets.

Our operations are conducted through our five operating limited partnerships and

their subsidiaries and are grouped into four reportable business segments. These

segments are as follows:

o Products Pipelines--which consists of approximately 10,000 miles of

refined petroleum products pipelines that deliver gasoline, diesel

fuel, jet fuel and natural gas liquids to various markets; plus over

60 associated

<PAGE>

product terminals and petroleum pipeline transmix processing

facilities serving customers across the United States;

o Natural Gas Pipelines--which consists of approximately 14,000 miles of

natural gas transmission pipelines and gathering lines, plus natural

gas storage, treating and processing facilities, through which natural

gas is gathered, transported, stored, treated, processed and sold;

o CO2--which produces, transports through pipelines and markets carbon

dioxide, commonly called CO2, to oil fields that use carbon dioxide to

increase production of oil; owns interests in and/or operates ten oil

fields in West Texas; and owns and operates a crude oil pipeline

system in West Texas; and

o Terminals--which consists of approximately 95 owned or operated

liquids and bulk terminal facilities and more than 60 rail

transloading and materials handling facilities located throughout the

United States, that together transload, store and deliver a wide

variety of bulk, petroleum, petrochemical and other liquids products

for customers across the United States.

Generally, as utilization of our pipelines and terminals increases, our

fee-based revenues increase. We do not face significant risks relating directly

to short-term movements in commodity prices for two principal reasons. First, we

primarily transport and/or handle products for a fee and are not engaged in

significant unmatched purchases and resales of commodity products. Second, in

those areas of our business where we do face exposure to fluctuations in

commodity prices, primarily oil production in our CO2 business segment, we

engage in a hedging program to mitigate this exposure.

We regularly consider and enter into discussions regarding potential

acquisitions, including those from KMI or its affiliates, and are currently

contemplating potential acquisitions. Any such transaction would be subject to

negotiation of mutually agreeable terms and conditions, receipt of fairness

opinions and approval of the respective boards of directors. While there are

currently no unannounced purchase agreements for the acquisition of any material

business or assets, such transactions can be effected quickly, may occur at any

time and may be significant in size relative to our existing assets or

operations.

It is our intention to carry out the above business strategy, modified as

necessary to reflect changing economic conditions and other circumstances.

However, as discussed under Item 1A "Risk Factors" below, there are factors that

could affect our ability to carry out our strategy or affect its level of

success even if carried out.

Recent Developments

The following is a brief listing of significant developments since December

31, 2005. Additional information regarding most of these items may be found

elsewhere in this report.

o On January 12, 2006, we 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 our 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;

o Effective February 23, 2006, Rockies Express Pipeline LLC acquired

Entrega Gas Pipeline LLC from EnCana Corporation for $244.6 million in

cash. West2East Pipeline LLC is a limited liability company and is the

sole owner of Rockies Express Pipeline LLC. We contributed 66 2/3% of

the consideration for this purchase, which corresponded to our

percentage ownership of West2East Pipeline LLC at that time.

At the time of

<PAGE>

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, Entrega 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, we 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 complete 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 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 our

subsidiary Kinder Morgan W2E Pipeline LLC, we continue to operate the

project but our 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, our ownership interest will be reduced to 50% at which time

the capital accounts of West2East Pipeline LLC will be trued up to

reflect our 50% economics in the project. We do not anticipate any

additional changes in the ownership structure of the 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, we 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

<PAGE>

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;

o On March 7, 2006, our 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 our 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 in its July 2004 BP West Coast Products

v. FERC opinion, including the level of income tax allowance that our

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 state of our Pacific operations'

rates that are currently pending on appeal before the District of

Columbia Circuit Court of Appeals.

On April 28, 2006, the FERC issued an order accepting our 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, we

were 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 our compliance filings.

The FERC indicated that a subsequent order would address the issues

raised in these comments. In December 2005, we recognized a $105.0

million non-cash expense attributable to an increase in our reserves

related to our 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 16 to our

consolidated financial statements;

o On March 9, 2006, we announced that we have entered into a long-term

agreement with Drummond Coal Sales, Inc. that will support a $70

million expansion of our 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, our Pier IX terminal can store

approximately 1.4 million tons of coal and 30,000 tons of cement on

its 30-acre storage site;

o Effective April 1, 2006, we sold our Douglas natural gas gathering

system and our Painter Unit fractionation facility to Momentum Energy

Group, LLC for approximately $42.5 million in cash. Our investment in

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;

o 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, we divested certain

acquired

<PAGE>

properties that were not considered candidates for carbon dioxide

enhanced oil recovery, thus reducing our total investment. We received

proceeds of approximately $27.1 million from the sale of these

properties. The 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 our current

carbon dioxide operations;

o On April 18, 2006, we announced that our 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;

o In April 2006, we acquired terminal assets and operations from A&L

Trucking, L.P. and U.S. Development Group in three separate

transactions for an aggregate consideration of approximately $61.9

million, consisting of $61.6 million in cash and $0.3 million in

assumed liabilities. The first transaction included the acquisition of

equipment and infrastructure 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 our existing Texas petroleum coke terminal operations by

providing bulk product customers with rail transportation options.

Thirdly, we acquired the entire membership interest of Lomita Rail

Terminal LLC, a limited liability company that owns a high-volume rail

ethanol terminal in Carson, California. The terminal 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;

o On May 17, 2006, we 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 our 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, we filed a new tariff, which took effect September 1,

2006, lowering our Pacific Operations' going-forward rate, and we also

paid refunds to all shippers for the period April 1, 1999 through

August 31, 2006.

On September 28, 2006, we 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 our

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 funds were due. On

January 16, 2007, we and ExxonMobil informed the presiding judge that

we had reached a settlement in principle regarding the ExxonMobil

refund issue, and in February 2007, we and ExxonMobil reached

agreement regarding ExxonMobil's protest of the refund report, and

the protest was withdrawn. As of December 31, 2006, we made aggregate

payments pursuant to the agreement, including accrued interest, of

$19.1 million;

o On June 1, 2006, we announced that we had completed and fully placed

into service our $210 million expansion of our 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. We

announced the completion of the pipeline portion of the project on

April 19, 2006, and new transportation tariffs designed to earn a

return on our construction costs went into effect June 1, 2006.

In addition, we continue working on our second East Line expansion

project, which we 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

<PAGE>

new storage tanks at Tucson. The project is expected to cost

approximately $145 million. We are 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;

o On June 8, 2006, we announced an approximate $76 million expansion

project that will significantly increase capacity at our 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.

Our North Dayton natural gas storage facility is connected to our

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 to $82 million, and the additional capacity is expected

to be available in mid-2009;

o On June 21, 2006, we announced that we, through our 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 KMI's Trans Mountain Pipeline crude oil

storage facility. In addition, we 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 KMI'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;

o On June 23, 2006, our 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 in 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;

o In August 2006, we completed a public offering of 5,750,000 of our

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. We received net proceeds

of $248.0 million for the issuance of these 5,750,000 common units,

and we used the proceeds to reduce the borrowings under our commercial

paper program;

o Effective August 28, 2006, we terminated our $250 million unsecured

nine month credit facility due November 21, 2006, and we increased our

five-year unsecured revolving credit facility from a total commitment

of $1.6 billion to $1.85 billion. Our 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 our five-year credit facility as of December 31, 2006. Our

credit facility primarily serves as a backup to our commercial paper

program, which had $1,098.2 million outstanding as of December 31,

2006;

o On September 8, 2006, we filed an application with the FERC requesting

approval to construct and operate our 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 we procured long-lead items, such as

line pipe and mainline

<PAGE>

block valves. We are currently finalizing interconnect agreements,

preparing detailed designs of the facilities and acquiring necessary

right-of-ways.

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 (an offshoot will consist of approximately 2.3 miles of

24-inch diameter pipeline with firm peak day capacity of approximately

300 million cubic feet per day extending away from the 42-inch

diameter line to the existing Florida Gas Transmission Company

compressor station in Acadia Parish, Louisiana); and (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 KMI's Natural Gas Pipeline Company of

America's natural gas pipeline. In addition, in exchange for shipper

commitments to the project, we have granted options to acquire equity

in the project, which, if fully exercised, could result in us 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 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

Environmental Impact Statement;

o On September 11, 2006, we announced major expansions at our 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 our Pasadena and Galena Park

terminals; (ii) an additional cross-channel pipeline to increase the

connectivity between the two terminals; (iii) a new ship dock at

Galena Park; and (iv) an additional loading bay at our fully automated

truck loading rack located at our Pasadena terminal. The expansions

are supported by long-term customer commitments and will result in

approximately 3.4 million barrels of additional tank storage capacity

at the two terminals. Construction began in October 2006 and all of

the projects are expected to be completed by the spring of 2008;

o On October 19, 2006, we announced the third of three investments in

our 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:

o the first project, estimated to cost approximately $10 million,

involves pipeline expansions that will 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 our

Las Vegas terminal;

o the second project, expected to cost approximately $15 million,

includes the installation of new and upgraded pumping equipment

and piping at our Colton, California terminal, a new booster

station with two pumps at Cajon, California, and piping upgrades

at our Las Vegas terminal; and

o 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

<PAGE>

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, we are currently working with our customers to

determine interest in the construction of a new refined products

distribution terminal to be located south of Henderson, Nevada;

o Effective November 20, 2006, we 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;

o Effective December 1, 2006, we 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 our existing dry-bulk terminal

operations;

o On December 13, 2006, we announced that we 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. We 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 KMI's 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 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.;

o On December 14, 2006, we announced that we expect to declare cash

distributions of $3.44 per unit for 2007, an almost 6% increase over

our cash distributions of $3.26 per unit for 2006. This expectation

includes contributions from assets owned by us as of the announcement

date and does not include any potential benefits from unidentified

acquisitions. We expect our growth to accelerate in the second half of

2007, and we anticipate that our fourth quarter 2007 distribution per

unit will be approximately 10% higher than our

<PAGE>

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

our 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;

o During 2006, we spent $1,058.3 million for additions to our property,

plant and equipment, including both expansion and maintenance

projects. Our capital expenditures included the following:

o $307.7 million in our Terminals segment, largely related to

expanding the petroleum products storage capacity at our liquids

terminal facilities, including the construction of additional

liquids storage tanks at our facilities on the Houston Ship

Channel, and to various expansion projects and improvements

undertaken at multiple bulk terminal facilities;

o $283.0 million in our CO2 segment, mostly related to additional

infrastructure, including wells and injection and compression

facilities, to support the expanding carbon dioxide flooding

operations at the SACROC and Yates oil field units in West Texas;

o $271.6 million in our Natural Gas Pipelines 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 our Texas

Intrastate natural gas pipeline systems, including the

development of additional natural gas storage capacity at our

natural gas storage facilities located at Markham and Dayton,

Texas; and

o $196.0 million in our Products Pipelines segment, mostly related

to the continued expansion work on our Pacific operations' East

Line products pipeline, the construction of an additional refined

products line on our 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 our Southeast terminal operations.

o On January 15, 2007, we announced that we had entered into an

agreement with affiliates of BP to increase our ownership interest in

the Cochin pipeline system to 100%. We purchased our original

undivided 32.5% ownership interest in the Cochin pipeline system in

November 2000, and we currently own 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, we will become the operator of the

pipeline;

o On January 17, 2007, we announced that our CO2 business segment will

invest approximately $120 million to further expand its operations and

enable it to meet the increased demand for carbon dioxide in the

Permian Basin. The expansion activities will take place in southwest

Colorado and 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. Upon completion, these expansion projects are expected

to be immediately accretive to distributable cash available to our

unitholders; and

o On January 30, 2007, we completed a public offering of senior notes.

We issued a total of $1.0 billion in principal amount of senior notes,

consisting of $600 million of 6.00% notes due February 1, 2017, and

$400 million of 6.50% notes due February 1, 2037. We received proceeds

from the issuance of the notes, after underwriting discounts and

commissions, of approximately $992.8 million, and we used the proceeds

to reduce the borrowings under our commercial paper program.

<PAGE>

(b) Financial Information about Segments

For financial information on our four reportable business segments, see

Note 15 to our consolidated financial statements.

Products Pipelines

Our Products Pipelines segment consists of our refined petroleum products

and natural gas liquids pipelines and their associated terminals, our Southeast

terminals and our transmix processing facilities.

Pacific Operations

Our Pacific operations include our SFPP, L.P. operations, our CALNEV

Pipeline operations and our West Coast terminals operations. The assets include

interstate common carrier pipelines regulated by the FERC, intrastate pipelines

in the State of California regulated by the California Public Utilities

Commission, and certain non rate-regulated operations and terminal facilities.

Our Pacific operations serve seven western states with approximately 3,000

miles of refined petroleum products pipelines and related terminal facilities

that provide refined products to some of the fastest growing population centers

in the United States, including California; Las Vegas and Reno, Nevada; and the

Phoenix-Tucson, Arizona corridor. For 2006, the three main product types

transported were gasoline (61%), diesel fuel (22%) and jet fuel (17%).

Our Pacific operations' pipeline system consists of seven pipeline

segments, which include the following:

o 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;

o 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 our

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;

o 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;

o the CALNEV Line, which consists of two parallel 248-mile, 14-inch and

8-inch diameter pipelines that run from our facilities at Colton,

California to Las Vegas, Nevada, and which also serves Nellis Air

Force Base located in Las Vegas. It also includes approximately 55

miles of pipeline serving Edwards Air Force Base;

o 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;

o the Bakersfield Line, which is a 100-mile, 8-inch diameter pipeline

serving Fresno, California; and

o 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.

<PAGE>

Our 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 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. We also have two petroleum product terminals located in Portland, Oregon

and one in Seattle, Washington.

Our Pacific operations include 15 truck-loading terminals (13 on SFPP, L.P.

and two on CALNEV) with an aggregate usable tankage capacity of approximately

13.5 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, our 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, our 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 our 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 us,

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 our 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 our Pacific operations'

pipeline system are proprietary pipelines owned and operated by major oil

companies in the area where our pipeline system delivers products as well as

refineries with related terminal and trucking arrangements within our market

areas. We believe that high capital costs, tariff regulation, and environmental

and right-of-way permitting considerations make it unlikely that a competing

pipeline system comparable in size and scope to our Pacific operations will be

built in the foreseeable future. However, the possibility of individual

pipelines being constructed or expanded to serve specific markets is a

continuing competitive factor.

The use of trucks for product distribution from either shipper-owned

proprietary terminals or from their refining centers continues to compete for

short haul movements by pipeline. We cannot predict with any certainty whether

the use of short haul trucking will decrease or increase in the future.

<PAGE>

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 our West Line to our East Line. Increased

movements into the Arizona market from El Paso could displace lower tariff

volumes supplied from Los Angeles on our West Line. Such shift of supply

sourcing has not had, and is not expected to have, a material effect on our

operating results.

Our Pacific operation's terminals compete with terminals owned by our

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 our 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 our Richmond

terminal's chemical business comes primarily from IMTT. Competitors to our

Portland, Oregon terminals include ST Services, ChevronTexaco and Shell Oil

Products U.S. Competitors to our Seattle petroleum products terminal primarily

include BP and Shell Oil Products U.S.

Plantation Pipe Line Company

We own 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. We operate 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.

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Central Florida Pipeline

Our Central Florida pipeline system consists of a 110-mile, 16-inch

diameter pipeline that transports gasoline and an 85-mile, 10-inch diameter

pipeline that transports diesel fuel and jet fuel from Tampa to Orlando, with an

intermediate delivery point on the 10-inch pipeline at Intercession City,

Florida. In addition to being connected to our Tampa terminal, the pipeline

system is connected to terminals owned and operated by TransMontaigne, Citgo,

BP, and Marathon Petroleum. The 10-inch diameter pipeline is connected to our

Taft, Florida terminal (located near Orlando) and is also the sole pipeline

supplying jet fuel to the Orlando International Airport in Orlando, Florida. In

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.

We also own and operate 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. We distribute approximately 150,000 barrels of refined

petroleum products per day including the Tampa terminal truck loadings. The

balance of the market is supplied primarily by trucking firms and marine

transportation firms. Most of the jet fuel used at Orlando International Airport

is moved through our Tampa terminal and the Central Florida pipeline system. The

market in Central Florida is seasonal, with demand peaks in March and April

during spring break and again in the summer vacation season, and is also heavily

influenced by tourism, with Disney World and other 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. We are utilizing tariff

incentives to attract volumes to the pipeline that might otherwise enter the

Orlando market area by truck from Tampa or by marine vessel into Cape Canaveral.

We believe it is unlikely that a new pipeline system comparable in size and

scope to our Central Florida Pipeline system will be constructed, due to the

high cost of pipeline construction, tariff regulation and environmental and

right-of-way permitting in Florida. However, the possibility of such a pipeline

or a smaller capacity pipeline being built is a continuing competitive factor.

With respect to the terminal operations at Tampa, the most significant

competitors are proprietary terminals owned and operated by major oil companies,

such as Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and

the 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.

<PAGE>

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

Our 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, our North

System's pipeline system connects mid-continent producing areas to markets in

the Midwest and eastern United States. We also have defined sole carrier rights

to use capacity on an extensive pipeline system owned by Magellan Midstream

Partners, L.P. that interconnects with our North System. This capacity lease

agreement, which requires us to pay approximately $2.3 million per year, is in

place until February 2013 and contains a five-year renewal option.

In addition to our capacity lease agreement with Magellan, we also have 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. We have an annual minimum joint tariff commitment of $0.6

million to Magellan for this agreement. Our 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 our truck-loading terminals.

We also own 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. We include our equity interest in

Heartland as part of our North System operations. ConocoPhillips owns the

remaining 50% interest in the Heartland Pipeline Company. The Heartland pipeline

comprises one of our North System's main line sections that originate at

Bushton, Kansas and terminates at a storage and terminal area in Des Moines,

Iowa. We operate 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 us for reserved pipeline capacity, is paid

monthly, with an annual adjustment. The 2007 lease fee will be approximately

$1.1 million.

In addition, our 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 our Morris terminal.

Markets. Our 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 our North

System. Other sources of natural gas liquids transported in our 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 our 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 our North System's

line-fill on a year round basis, we added isobutane as a component of line-fill

in 2005, and we 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.

<PAGE>

Competition. Our 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, our

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 our North System for propane terminal

deliveries. Our North System also competes indirectly with pipelines that

deliver product to markets that our 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

We own 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, we announced that we had entered into an agreement with BP Canada Energy

Company to increase our 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, we 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 our

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 liquids market comes from the combination of the Alliance pipeline

system, which brings unprocessed gas into the United States from Canada, and

from Aux Sable, which processes and markets the natural gas liquids in the

Chicago market.

Cypress Pipeline

Our Cypress pipeline is an interstate common carrier natural gas liquids

pipeline originating at storage facilities in Mont Belvieu, Texas and extending

104 miles east to a major petrochemical producer in the Lake Charles, Louisiana

area. Mont Belvieu, located approximately 20 miles east of Houston, is the

largest hub for natural gas liquids gathering, transportation, fractionation and

storage in the United States.

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

<PAGE>

pipelines into ethane and other components. Additionally, pipeline systems that

transport natural gas liquids from major producing areas in Texas, New Mexico,

Louisiana, Oklahoma and the Mid-Continent Region supply ethane and

ethane/propane mix to Mont Belvieu.

Competition. The pipeline's primary competition into the Lake Charles

market comes from Louisiana onshore and offshore natural gas liquids.

Southeast Terminals

Our Southeast terminal operations consist of Kinder Morgan Southeast

Terminals LLC and its consolidated affiliate, Guilford County Terminal Company,

LLC. Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred

to in this report as KMST, was formed 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:

o 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 us

to use the terminals. All seven terminals are served by the Colonial

Pipeline and three are also connected to the Plantation Pipeline;

o seven petroleum products terminals acquired from ExxonMobil

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;

o 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. We fully own seven of the terminals and jointly own the

remaining two. All nine terminals are connected to Plantation or

Colonial pipelines; and

o 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 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.

<PAGE>

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

Our Transmix operations include the processing of petroleum pipeline

transmix, a blend of dissimilar refined petroleum products that have become

co-mingled in the pipeline transportation process. During transportation,

different products are transported through the pipelines abutting each other,

and the volume of different mixed products is called transmix. At our transmix

processing facilities, we process and separate pipeline transmix into

pipeline-quality gasoline and light distillate products. We process transmix at

six separate processing facilities located in Colton, California; Richmond,

Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River,

Illinois; and Greensboro, North Carolina.

At our 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. We process transmix 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 our 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 us, 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 us, as well

as an opportunity to extend the processing agreement beyond 2011.

Our Colton processing facility is located adjacent to our products terminal

in Colton, California, and it produces refined petroleum products that are

delivered into our 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 our long term processing contract due to

expire in 2010. Following Duke's exercise, we transitioned to processing

transmix at Colton for various pipeline shippers directly on a "for fee" basis

arrangement.

Our 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.

Our 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. Our 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.

Our 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, we completed construction and placed into

service our 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 our East

Coast transmix processing operations. The Mid-Continent area and the New York

Harbor are the target markets for our Illinois and Pennsylvania assets,

respectively. Our West Coast transmix processing operations support the markets

served by our Pacific operations in Southern Califormia.

<PAGE>

Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer

and our Pacific operations provide the vast majority of the supply. These

suppliers are committed to the use of our transmix facilities under long-term

contracts. Individual shippers and terminal operators provide additional supply.

Shell acquires transmix for processing at Indianola, Richmond and Wood River;

Colton is supplied by pipeline shippers of our Pacific operations; and Dorsey

Junction is supplied by Colonial Pipeline Company.

Competition. Placid Refining is our main competitor in the Gulf Coast area.

There are various processors in the Mid-Continent area, primarily

ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with

our transmix facilities. 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 our Indianola facility. A number of smaller

organizations operate transmix processing facilities in the West and Southwest.

These operations compete for supply that we envision as the basis for growth in

the West and Southwest. Our Colton processing facility also competes with major

oil company refineries in California.

Natural Gas Pipelines

Our Natural Gas Pipelines segment, which contains both interstate and

intrastate pipelines, consists of natural gas sales, transportation, storage,

gathering, processing and treating. Within this segment, we own 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. Our transportation network provides access to the major gas supply areas

in the western United States, Texas and the Midwest, as well as major consumer

markets.

Texas Intrastate Natural Gas Pipeline Group

The group, which operates primarily along the Texas Gulf Coast, consists of

the following four natural gas pipeline systems:

o our Kinder Morgan Texas Pipeline;

o our Kinder Morgan Tejas Pipeline;

o our Mier-Monterrey Mexico Pipeline; and

o our Kinder Morgan North Texas Pipeline.

The two largest systems in the group are our Kinder Morgan Texas Pipeline

and our Kinder Morgan Tejas Pipeline. These pipelines essentially operate as a

single pipeline system, providing customers and suppliers with improved

flexibility and reliability. The combined system includes approximately 6,000

miles of intrastate natural gas pipelines with a peak transport and sales

capacity of approximately 5.2 billion cubic feet per day of natural gas and

approximately 120 billion cubic feet of 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 our Kinder Morgan Tejas system is our Kinder

Morgan Border Pipeline system. Kinder Morgan Border owns and operates an

approximately 97-mile, 24-inch diameter pipeline that extends from a point of

interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica

at the International Border between the United States and Mexico, to a point of

interconnection with other intrastate pipeline facilities of Kinder

<PAGE>

Morgan Tejas located at King Ranch, Kleburg County, Texas. The 97-mile pipeline,

referred to as the import/export facility, is capable of importing Mexican gas

into the United States, and exporting domestic gas to Mexico. The imported

Mexican gas is received from, and the exported domestic gas is delivered to,

Pemex. The capacity of the import/export facility is approximately 300 million

cubic feet of natural gas per day.

Our Mier-Monterrey Pipeline consists of a 95-mile, 30-inch diameter natural

gas pipeline that stretches from south Texas to Monterrey, Mexico and can

transport up to 375 million cubic feet per day. The pipeline connects to a

1,000-megawatt power plant complex and to the PEMEX natural gas transportation

system. We have entered into a long-term contract (expiring in 2018) with Pemex,

which has subscribed for all of the pipeline's capacity.

Our North Texas Pipeline consists of an 86-mile, 30-inch diameter pipeline

that transports natural gas from an interconnect with KMI's Natural Gas Pipeline

Company of America in Lamar County, Texas to a 1,750-megawatt electric

generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It

has the capacity to transport 325 million cubic feet per day of natural gas and

is fully subscribed under a long-term contract that expires in 2032. In 2006,

the existing system was enhanced to be bi-directional, so that deliveries of

additional supply coming out of the Barnett Shale area can be delivered into

NGPL's pipeline as well as power plants in the area.

We also own and operate various gathering systems in South and East Texas.

These systems aggregate natural gas supplies into our main transmission

pipelines, and in certain cases, aggregate natural gas that must be processed or

treated at its own or third-party facilities. We own two processing plants: our

Texas City Plant in Galveston County, Texas and our 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, we have contractual rights to process approximately 800 million cubic

feet per day of natural gas at various third-party owned facilities. We also own

and operate three natural gas treating plants that offer carbon dioxide and/or

hydrogen sulfide removal. We can treat up to 155 million cubic feet per day of

natural gas for carbon dioxide removal at our Fandango Complex in Zapata County,

Texas, 50 million cubic feet per day of natural gas at our Indian Rock Plant in

Upshur County, Texas and approximately 45 million cubic feet per day of natural

gas at our Thompsonville Facility located in Jim Hogg County, Texas.

Our North Dayton natural gas storage facility, located in Liberty County,

Texas, has two existing storage caverns providing approximately 6.3 billion

cubic feet of total capacity, consisting of 4.2 billion cubic feet of working

capacity and 2.1 billion cubic feet of pad gas. We have 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, we announced an expansion project that will significantly increase

natural gas storage capacity at our 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.

We also own 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 we provide transportation service into and out of the

facility.

Additionally, we lease a salt dome storage facility located near Markham,

Texas according to the provisions of an operating lease that expires in March

2013. We can, at our sole option, extend the term of this lease for two

additional ten-year periods. The facility 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. We also lease

two salt dome caverns, known as the Stratton Ridge Facilities, from BP America

Production Company in Brazoria County, Texas. The Stratton Ridge Facilities have

a combined working natural gas capacity of 1.4 billion cubic feet and a peak day

deliverability of 100 million cubic feet per day. A lease with Dow Hydrocarbon &

Resources, Inc. for a salt dome cavern containing approximately 5.0 billion

cubic feet of working capacity 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 our 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.

<PAGE>

The industrial demand is primarily year-round load. Merchant and utility power

demand peaks in the summer months and is complemented by local natural gas

distribution demand that peaks in the winter months. As new merchant gas fired

generation has come online and displaced traditional utility generation, we have

successfully attached many of these new generation facilities to our pipeline

systems in order to maintain and grow our share of natural gas supply for power

generation. Additionally, in 2007, we have increased our capability and

commitment to serve the growing local natural gas distribution market in the

greater Houston metropolitan area.

We serve the Mexico market through interconnection with the facilities of

Pemex at the United States-Mexico border near Arguellas, Mexico and 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 generally ranged

from zero to 322 million cubic feet per day. We primarily provide transport

service to these markets on a fee for service basis, including a significant

demand component, which is paid regardless of actual throughput. Revenues earned

from our activities in Mexico are paid in U.S. dollar equivalent.

Supply. We purchase our natural gas directly from producers attached to our

system in South Texas, East Texas and along the Texas Gulf Coast. We also

purchase gas at interconnects with third-party interstate and intrastate

pipelines. While our intrastate group does not produce gas, it does maintain an

active well connection program in order to offset natural declines in production

along its system and to secure supplies for additional demand in its market

area. Our intrastate system has access to both onshore and offshore sources of

supply, and is well positioned to interconnect with liquefied natural gas

projects currently under development by others along the Texas Gulf Coast.

Competition. The Texas intrastate natural gas market is highly competitive,

with many markets connected to multiple pipeline companies. We compete with

interstate and intrastate pipelines, and their shippers, for attachments to new

markets and supplies and for transportation, processing and treating services.

Kinder Morgan Interstate Gas Transmission LLC

Kinder Morgan Interstate Gas Transmission LLC, referred to in this report

as KMIGT, along with our Trailblazer Pipeline Company, our TransColorado Gas

Transmission Company, and our current 51% ownership interest in the Rockies

Express Pipeline (all discussed following) comprise our 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, and 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 which include the retention of fuel and gas lost and unaccounted for

in-kind. Under KMIGT's tariffs, firm transportation and storage customers pay

reservation 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

<PAGE>

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 our

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 KMI's U.S. retail natural gas distribution

operations, and in August 2006, KMI entered into a definitive agreement with a

subsidiary of General Electric Company to sell KMI's U.S. retail natural gas

distribution and related operations. Pending regulatory approvals, KMI expects

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

Our 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

Natural Gas Pipeline Company of America's and Northern Natural Gas Company's

pipeline systems. Natural Gas Pipeline Company of America, a subsidiary of KMI,

manages, maintains and operates Trailblazer, for which it is reimbursed at cost.

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

<PAGE>

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

Our 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. KMI

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 which include the retention of fuel and gas lost and unaccounted for

in-kind. Under TransColorado's tariffs, firm transportation customers pay

reservation charges each month plus a commodity charge based on actual volumes

transported. Interruptible transportation customers pay a commodity charge based

upon actual volumes transported. The underlying reservation and commodity

charges are assessed pursuant to a maximum recourse rate structure, which does

not vary based on the distance gas is transported. TransColorado has the

authority to negotiate rates with customers if it has first offered service to

those customers under its reservation and commodity charge rate structure.

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.

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, 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

<PAGE>

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

We operate and currently own 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,

we 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, our ownership interest will be reduced to 50% and the

capital accounts of West2East Pipeline LLC will be trued up to reflect our 50%

economics in the project. We do not anticipate any additional changes in the

ownership structure of the project.

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 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.

<PAGE>

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, we 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, we filed an application with the FERC requesting

approval to construct and operate our Kinder Morgan Louisiana Pipeline. The

natural gas pipeline project is expected to cost approximately $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, we have granted options

to acquire equity in the project, which, if fully exercised, could result in us

owning a minimum interest of 80% after the project is completed.

The Kinder Morgan Louisiana Pipeline will consist of two segments:

o 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

o 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 KMI's Natural Gas Pipeline Company

of America's natural gas pipeline. This portion of the project is

expected to be in service in the third quarter of 2008.

We have designed and will construct the Kinder Morgan Louisiana Pipeline in

a manner that will minimize environmental impacts, and where possible, existing

pipeline corridors will be used to minimize impacts to communities and to the

environment. As of December 31, 2006, there were no major pipeline re-routes as

a result of any landowner requests. We are 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

We own and operate our 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 our 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 our

Casper plant.

We also own and operate our 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, we sold our Wyoming natural gas gathering system

and our Painter Unit fractionation facility to a third party for approximately

$42.5 million in cash. For more information on this sale, see Note 3 to our

consolidated financial statements included elsewhere in this report.

<PAGE>

Markets. Casper and Douglas are processing plants servicing gas streams

flowing into KMIGT. Natural gas liquids processed by our Casper plant are sold

into local markets consisting primarily of retail propane dealers, oil refiners,

and ethanol production facilities. Natural gas liquids processed by our Douglas

plant are sold to ConocoPhillips via their Powder River natural gas liquids

pipeline for either ultimate consumption at the Borger refinery or for further

disposition to the natural gas liquids trading hubs located in Conway, Kansas

and Mont Belvieu, Texas.

Competition. Other regional facilities in the Greater Powder River Basin

include the Hilight plant (80 million cubic feet per day) owned and operated by

Anadarko, the Sage Creek plant (50 million cubic feet per day) owned and

operated by Merit Energy, and the Rawlins plant (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

We own a 49% equity interest in the Red Cedar Gathering Company, a joint

venture organized in August 1994 and referred to in this report as Red Cedar.

The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian

Tribe. Red Cedar owns and operates natural gas gathering, compression and

treating facilities in the Ignacio Blanco Field in La Plata County, Colorado.

The Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin,

most of which is located within the exterior boundaries of the Southern Ute

Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural

gas at wellheads and several central delivery points, for treating, compression

and delivery into any one of four major interstate natural gas pipeline systems

and an intrastate pipeline.

Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as

Coyote Gulch. Previously, we 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. We 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

We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred

to in this report as Thunder Creek. Devon Energy owns the remaining 75%. Thunder

Creek provides gathering, compression and treating services to a number of coal

seam gas producers in the Powder River Basin of Wyoming. Throughput volumes

include both coal seam and conventional plant residue gas. Thunder Creek 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

<PAGE>

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

Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated

affiliates, referred to in this report as KMCO2. Carbon dioxide is used in

enhanced oil recovery projects as a flooding medium for recovering crude oil

from mature oil fields. Our carbon dioxide pipelines and related assets allow us

to market a complete package of carbon dioxide supply, transportation and

technical expertise to the customer. Together, our CO2 business segment

produces, transports and markets carbon dioxide for use in enhanced oil recovery

operations. We also hold ownership interests in several oil-producing fields and

own a 450-mile crude oil pipeline, all located in the Permian Basin region of

West Texas.

Carbon Dioxide Reserves

We own approximately 45% of, and operate, the McElmo Dome unit, 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. We also own

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.

We also own approximately 88% of the Doe Canyon Deep unit, which contains

more than 1.5 trillion cubic feet of carbon dioxide. We are 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. Our principal market for carbon dioxide is for injection into

mature oil fields in the Permian Basin, where industry demand is expected to

grow modestly for the next several years. We are exploring additional potential

markets, including enhanced oil recovery targets in California, Wyoming, the

Gulf Coast, Mexico, and Canada, and coal bed methane production in the San Juan

Basin of New Mexico.

Competition. Our primary competitors for the sale of carbon dioxide include

suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep

Mountain carbon dioxide reserves, and Petro-Source Carbon Company, which gathers

waste carbon dioxide from natural gas production in the Val Verde Basin of West

Texas. There is no assurance that new carbon dioxide sources will not be

discovered or developed, which could compete with us or that new methodologies

for enhanced oil recovery will not replace carbon dioxide flooding.

Carbon Dioxide Pipelines

As a result of our 50% ownership interest in Cortez Pipeline Company, we

own a 50% equity interest in and operate the approximate 500-mile, 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 our Central Basin pipeline and our Centerline pipeline.

Our 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 lateral supply lines

located in the Permian Basin between Denver City, Texas and McCamey, Texas with

a throughput capacity of 600 million cubic feet per day. At its origination

point in Denver City, our Central Basin pipeline interconnects with all three

major carbon dioxide supply pipelines from Colorado and New Mexico, namely the

Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines

(operated by Occidental and Trinity CO2, respectively). Central Basin's mainline

terminates near McCamey where

<PAGE>

it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline.

The tariffs charged by the Central Basin pipeline are not regulated.

Our Centerline pipeline consists of approximately 113 miles of 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. We

constructed this pipeline and placed it in service in May 2003. The tariffs

charged by the Centerline pipeline are not regulated.

We own 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, we own approximately 98% of the Canyon Reef Carriers pipeline

and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline

extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a

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.

Markets. The principal market for transportation on our carbon dioxide

pipelines is to customers, including ourselves, using carbon dioxide for

enhanced recovery operations in mature oil fields in the Permian Basin, where

industry demand is expected to grow modestly for the next several years.

Competition. Our ownership interests in the Central Basin, Cortez and Bravo

pipelines are in direct competition with other carbon dioxide pipelines. We also

compete with other interest owners in McElmo Dome and Bravo Dome for

transportation of carbon dioxide to the Denver City, Texas market area.

Oil 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.

Our plan has been to increase the production rate and ultimate oil recovery

from Yates by combining horizontal drilling with carbon dioxide injection to

ensure a relatively steady production profile over the next several years.

<PAGE>

We are implementing our 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 our

operations at SACROC, where we use carbon dioxide and water to drive oil to the

producing wells, we are using carbon dioxide injection to replace nitrogen

injection at Yates in order to enhance the gravity drainage process, as well as

to maintain reservoir pressure. The differences in geology and reservoir

mechanics between the two fields mean that substantially less capital will be

needed to develop the reserves at Yates than is required at SACROC.

We also operate and own an approximate 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.

We are 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, we 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 our acquisition, we divested certain acquired properties that

were not considered candidates for carbon dioxide enhanced oil recovery, and we

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. We are presently evaluating operating and

subsurface technical data to further assess redevelopment opportunities for the

Katz field including the potential for carbon dioxide flood operations.

Oil Acreage and Wells

The following table sets forth productive wells, service wells and drilling

wells in the oil and gas fields in which we own interests as of December 31,

2006. When used with respect to acres or wells, gross refers to the total acres

or wells in which we have a working interest; net refers to gross acres or wells

multiplied, in each case, by the percentage working interest owned by us:

<TABLE>

Productive Wells (a) Service Wells (b) 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

========= ======= ======== ======= ========= =======

</TABLE>

(a) Includes active wells and wells temporarily shut-in. As of December 31,

2006, we 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.

December 31, 2006. A development well is a well drilled in an already

discovered oil field.

The oil and gas producing fields in which we own interests are located in

the Permian Basin area of West Texas and New Mexico. The following table

reflects our 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

====== ====== ======

--------

<PAGE>

Notes: The above table includes wells that were completed during each year

regardless of the year in which drilling was initiated, and does not

include any wells where drilling operations were not completed as of

the end of the applicable year. Development wells include wells

drilled in the proved area of an oil or gas resevoir.

The following table reflects the developed and undeveloped oil and gas

acreage that we held as of December 31, 2006:

Gross Net

-------- ---------

Developed Acres........ 72,435 67,709

Undeveloped Acres...... 8,788 8,131

-------- ---------

Total.............. 81,223 75,840

======== =========

Operating Statistics

Operating statistics from our 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

<TABLE>

Year Ended December 31,

--------------------------------

2006 2005 2004

-------- -------- -------

Consolidated Companies(a)

Production costs per barrel of oil equivalent(b)(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 Bbl(g).................................. $ 31.42 $ 27.36 $ 25.72

======= ======= =======

Natural gas liquids price per Bbl(g)........................ $ 43.52 $ 38.79 $ 31.37

======= ======= =======

Natural gas price per Mcf(h)................................ $ 6.36 $ 5.84 $ 5.27

======= ======= =======

Total natural gas liquids price per Bbl(e).................. $ 43.90 $ 38.98 $ 31.33

======= ======= =======

Total natural gas price per Mcf(e).......................... $ 7.02 $ 5.80 $ 5.24

======= ======= =======

Average sales prices excluding hedge gains/losses:

Crude oil price per Bbl(g).................................. $ 63.27 $ 54.45 $ 40.91

======= ======= =======

Natural gas liquids price per Bbl(g)........................ $ 43.52 $ 38.79 $ 31.68

======= ======= =======

Natural gas price per Mcf(h)................................ $ 6.36 $ 5.84 $ 5.27

======= ======= =======

</TABLE>

--------------

(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.

supplies, fuel and power, property taxes, severance taxes, and general and

administrative expenses directly related to oil and gas producing

activities.

(d) Includes only production attributable to leasehold ownership.

(e) Includes production attributable to our ownership in processing plants and

third party processing agreements.

(f) Excludes natural gas production used as fuel.

(g) Hedge gains/losses for crude oil and natural gas liquids are included with

crude oil.

(h) Natural gas sales were not hedged.

<PAGE>

See Note 20 to our consolidated financial statements included in this

report for additional information with respect to our oil and gas producing

activities.

Gas Plant Interests

We operate and own an approximate 22% working interest plus an additional

26% net profits interest in the Snyder gasoline plant. We also operate and own a

51% ownership interest in the Diamond M gas plant and a 100% ownership interest

in the North Snyder plant, all of which are located in the Permian Basin of West

Texas. The Snyder gasoline plant processes gas produced from the SACROC unit and

neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell

units, all of which are located in the Permian Basin area of West Texas. The

Diamond M and the North Snyder plants contract with the Snyder plant to process

gas. Production of natural gas liquids at the Snyder gasoline plant as of

December 2006 was approximately 15,000 barrels per day, the same rate of

production as of December 2005.

Crude Oil Pipeline

We own our 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 us to better manage crude oil deliveries

from our oil field interests in West Texas, and we have entered into a long-term

throughput agreement with Western Refining Company, L.P. to transport crude oil

into Western's 120,000 barrel per day refinery in El Paso. The 20-inch pipeline

segment transported approximately 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

Our Terminals segment includes the operations of our petroleum, chemical

and other liquids terminal facilities (other than those included in our Products

Pipelines segment) as well as all of our 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 our Terminals segment

received more than $0.1 million of revenue was approximately 550.

Liquids Terminals

Our liquids terminals operations primarily store refined petroleum

products, petrochemicals, industrial chemicals and vegetable oil products in

aboveground storage tanks and transfer products to and from pipelines, tank

trucks, tank barges, and tank railcars. Combined, our liquids terminals

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. Our major

liquids terminals assets are described below.

Our 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. Since our acquisition of

the terminal complex in January 2001, we have added more than 3.7 million

barrels of new storage capacity as refinery outputs along the Gulf Coast have

continued to increase. We have also upgraded our pipeline manifold connection

with the Colonial Pipeline system, added pipeline connections to new refineries,

and expanded our truck rack. 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, we announced major expansions at our Pasadena and Galena

Park, Texas terminal facilities. The expansions will provide additional

infrastructure to help meet the growing need for refined petroleum products

storage capacity along the Gulf Coast. The investment of approximately $195

million includes the construction of

<PAGE>

the following: (i) new storage tanks at both our Pasadena and Galena Park

terminals; (ii) an additional cross-channel pipeline to increase the

connectivity between the two terminals; (iii) a new ship dock at Galena Park;

and (iv) an additional loading bay at our fully automated truck loading rack

located at our Pasadena terminal. The expansions are supported by long-term

customer commitments and will result in approximately 3.4 million barrels of

additional tank storage capacity at the two terminals. Construction began in

October 2006, and all of the projects are expected to be completed by the spring

of 2008.

We own 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, of which 1.1 million barrels have been

added since our acquisition of the Carteret terminal in January 2001. Since our

acquisition, we also completed the construction of a 16-inch diameter pipeline

at Carteret that connects to the Buckeye pipeline system, a major products

pipeline serving the East Coast. Our 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, we 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.

Our 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.

In July 2005, we acquired the Kinder Morgan Staten Island terminal from

ExxonMobil Corporation. Located 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 we are currently rebuilding ship and barge berths at the facility that

will accommodate tanker vessels.

We own 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.

<PAGE>

Two of our other largest liquids facilities are located in South Louisiana:

our Port of New Orleans facility located in Harvey, Louisiana; and our 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.

Our 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, we 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 KMI'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.

Competition. We are one of the largest independent operators of liquids

terminals in North America. Our primary competitors are IMTT, Magellan, Morgan

Stanley, Oil Tanking, Teppco, Valero, and Vopak.

Bulk Terminals

Our bulk terminal operations primarily involve dry-bulk material handling

services; however, we also provide terminal engineering and design services and

in-plant services covering material handling, conveying, maintenance and repair,

railcar switching and miscellaneous marine services. Combined, our dry-bulk and

material transloading facilities handled approximately 89.5 million tons of

coal, petroleum coke, steel and other dry-bulk materials in 2006. We own or

operate approximately 28 petroleum coke or coal terminals in the United States.

Our major bulk terminal assets are described below.

In 2006, we 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 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 our 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 our purchase of certain

petroleum coke terminal operations from Trans-Global Solutions, Inc. in April

2005. We gave an aggregate consideration of approximately $247.2 million for

these operations, and the acquisition made us 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, we 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

<PAGE>

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 our coal terminals is

destined for use in coal-fired electric generation facilities.

Our 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. Our Cora terminal sits on the mainline

of the Union Pacific Railroad and is strategically positioned to receive coal

shipments from the western United States.

Our 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. Our 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.

Our 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.

Our 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. Our 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. Since early-2004,

Pier IX has also operated 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, we announced that we had 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.

Our Shipyard River Terminal is located in Charleston, South Carolina, on

208 acres, and is both a bulk and liquids terminal. Our 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. 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. We are currently expanding our 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.

Our Kinder Morgan Tampaplex terminal, a marine terminal acquired in

December 2003 and 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 our Port Sutton import terminal,

<PAGE>

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 our 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 our

Hartford Street terminal, anhydrous ammonia and fertilizers are handled and

stored in two warehouses with an aggregate capacity of 23,000 net tons.

Our 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.

Our 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.

Our 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.

Our 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. In the

fourth quarter of 2004, we completed the construction of a $19 million cement

loading facility at the Dakota terminal. The loading facility was built 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. Our 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 our 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. Our Cora and Grand Rivers coal terminals compete with two third-party

coal terminals that also serve the Midwest United States. While our 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. Our Pier IX terminal competes primarily

with two modern coal terminals located in the same Virginian port complex as our

Pier IX terminal.

Materials Services (rail transloading)

Our 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, we 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 3 to our consolidated financial statements included

elsewhere in this report.

Our 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). We also design and build

transloading facilities, perform

<PAGE>

inventory management services, and provide value-added services such as

blending, heating and sparging. In 2006, our materials services operations

handled approximately 72,000 railcars.

Major Customers

Our total operating revenues are derived from a wide customer base. For

each of the years ended December 31, 2006 and 2005, no revenues from

transactions with a single external customer accounted for 10% or more of our

total consolidated revenues. For the year ended December 31, 2004, only one

customer accounted for more than 10% of our total consolidated revenues. Total

transactions with CenterPoint Energy accounted for 14.3% of our total

consolidated revenues during 2004.

The high percentage of our total revenues attributable to CenterPoint

Energy in 2004 related to the merchant activity of our Texas intrastate natural

gas pipeline group, which both buys and sells significant volumes of natural gas

within the State of Texas. To a far lesser extent, our CO2 business segment also

sells natural gas, and combined, total revenues from the sales of natural gas

from our Natural Gas Pipelines and CO2 business segments in 2006, 2005 and 2004

accounted for 67.5%, 73.6% and 73.2%, respectively, of our total consolidated

revenues.

As a result of our Texas intrastate group selling natural gas in the same

price environment in which it is purchased, both our total consolidated revenues

and our total consolidated purchases (cost of sales) increase considerably due

to the inclusion of the cost of gas in both financial statement line items.

However, these higher revenues and higher purchased gas costs do not necessarily

translate into increased margins in comparison to those situations in which we

charge a fee to transport gas owned by others. Our Texas intrastate group

reported gross margins from the sale and purchases of natural gas of $190.2

million in 2006, $142.2 million in 2005 and $111.5 million in 2004. We do not

believe that a loss of revenues from any single customer would have a material

adverse effect on our business, financial position, results of operations or

cash flows.

Regulation

Interstate Common Carrier Pipeline Rate Regulation

Some of our 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 16

to our consolidated financial statements included elsewhere in this report.

<PAGE>

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 will apply 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 Transportation and Storage Regulation

Both the performance of and rates charged by companies performing

interstate natural gas transportation and storage services are regulated by the

FERC under the Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas

Policy Act of 1978. Beginning in the mid-1980's, the FERC initiated a number of

regulatory changes intended to create a more competitive environment in the

natural gas marketplace. Among the most important of these changes were:

o Order No. 436 (1985) requiring open-access, nondiscriminatory

transportation of natural gas;

o 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

o 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:

o requiring the unbundling of sales services from other services;

o 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

o the issuance of blanket sales certificates to interstate pipelines for

unbundled services.

Order 636 has been affirmed in all material respects upon judicial review,

and our own FERC orders approving our unbundling plans are final and not subject

to any pending judicial review.

On November 25, 2003, the FERC issued Order No. 2004, adopting revised

Standards of Conduct that apply uniformly to interstate natural gas pipelines

and public utilities. In light of the changing structure of the energy industry,

these Standards of Conduct govern relationships between regulated interstate

natural gas pipelines and all of their energy affiliates. These new Standards of

Conduct were designed to eliminate the loophole in the previous

<PAGE>

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 United States Court of Appeals for the District

of Columbia Circuit vacated Order No. 2004, as applied to natural gas pipelines,

and remanded the Order back to FERC. On January 9, 2007, the FERC issued an

interim rule regarding standards of conduct in Order 690 to be effective

immediately. The interim rule repromulgated the standards of conduct that were

not challenged before the court. On January 18, 2007, the FERC issued a notice

of proposed rulemaking soliciting comments on whether or not the interim rule

should be made permanent for natural gas transmission providers.

Please refer to Note 17 to our consolidated financial statements included

elsewhere in this report for additional information regarding FERC Order No.

2004 and other Standards of Conduct rulemaking.

On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The

Energy Policy Act, among other things, amended the Natural Gas Act to prohibit

market manipulation by any entity, directed the FERC to facilitate market

transparency in the market for sale or transportation of physical natural gas in

interstate commerce, and significantly increased the penalties for violations of

the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules,

regulations or orders thereunder.

California Public Utilities Commission Rate Regulation

The intrastate common carrier operations of our Pacific operations'

pipelines in California are subject to regulation by the California Public

Utilities Commission under a "depreciated book plant" methodology, which is

based on an original cost measure of investment. Intrastate tariffs filed by us

with the CPUC have been established on the basis of revenues, expenses and

investments allocated as applicable to the California intrastate portion of our

Pacific operations' business. Tariff rates with respect to intrastate pipeline

service in California are subject to challenge by complaint by interested

parties or by independent action of the CPUC. A variety of factors can affect

the rates of return permitted by the CPUC, and certain other issues similar to

those which have arisen with respect to our FERC regulated rates could also

arise with respect to our intrastate rates. Certain of our Pacific operations'

pipeline rates have been, and continue to be, subject to complaints with the

CPUC, as is more fully described in Note 16 to our consolidated financial

statements.

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

<PAGE>

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 16 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 increase the amount of these expenditures. Such expenditures

cannot be accurately estimated at this time.

State and Local Regulation

Our activities are subject to various state and local laws and regulations,

as well as orders of regulatory bodies, governing a wide variety of matters,

including marketing, production, pricing, pollution, protection of the

environment, and safety.

Environmental Matters

Our operations are subject to federal, state and local, and some foreign

laws and regulations governing the release of regulated materials into the

environment or otherwise relating to environmental protection or human health or

safety. We believe that our operations are in substantial compliance with

applicable environmental laws and regulations. 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

<PAGE>

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 $61.6 million as of

December 31, 2006. Our reserve estimates range in value from approximately $61.6

million to approximately $108.8 million, and we have recorded a liability equal

to the low end of the range. For additional information related to environmental

matters, see Note 16 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 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.

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act,

also known as the "Superfund" law or "CERCLA," and analogous state laws, impose

joint and several liability, without regard to fault or the legality of the

original conduct, on certain classes of "potentially responsible persons" for

releases of "hazardous substances" into the environment. These persons include

the owner or operator of a site and companies that disposed or arranged for the

disposal of the hazardous substances found at the site. CERCLA authorizes the

U.S. EPA and, in some cases, third parties to take actions in response to

threats to the public health or the environment and to seek to recover from the

responsible classes of persons the costs they incur, in addition to compensation

for natural resource damages, if any. Although "petroleum" is excluded from

CERCLA's definition of a "hazardous substance," in the course of our ordinary

operations, we have and will generate materials that may fall within the

definition of "hazardous substance." By operation of law, if we are determined

to be a potentially responsible person, we may be responsible under CERCLA for

all or part of the costs required to clean up sites at which such materials are

present, in addition to compensation for natural resource damages, if any.

Clean Air Act

Our operations are subject to the Clean Air Act, as amended, and analogous

state statutes. We believe that the operations of our pipelines, storage

facilities and terminals are in substantial compliance with such statutes. The

Clean Air Act, as amended, contains lengthy, complex provisions that may result

in the imposition over the next several years of certain pollution control

requirements with respect to air emissions from the operations of our

<PAGE>

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.

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.

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

<PAGE>

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:

o our Products Pipelines' terminals are storing and blending ethanol

because unlike MTBE, it cannot flow through refined petroleum products

pipelines;

o 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

o 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. In 2006, the liquids facilities

included within our Terminals' business segment reported a 159%

increase in the volumes of ethanol handled and/or transferred.

Other

We do not have any employees. KMGP Services Company, Inc. and Kinder

Morgan, Inc. employ all persons necessary for the operation of our business.

Generally, we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc. for

the services of their employees. As of December 31, 2006, KMGP Services Company,

Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 8,600

full-time employees. Approximately 2,100 full-time hourly personnel at certain

terminals and pipelines are represented by labor unions under collective

bargaining agreements that expire between 2007 and 2011. KMGP Services Company,

Inc. and Kinder Morgan, Inc. consider relations with their employees to be good.

For more information on our related party transactions, see Note 12 of the notes

to our consolidated financial statements included elsewhere in this report.

Substantially all of our pipelines are constructed on rights-of-way granted

by the apparent record owners of such property. In many instances, lands over

which rights-of-way have been obtained are subject to prior liens which have not

been subordinated to the right-of-way grants. In some cases, not all of the

apparent record owners have joined in the right-of-way grants, but in

substantially all such cases, signatures of the owners of majority interests

have been obtained. Permits have been obtained from public authorities to cross

over or under, or to lay facilities in or along, water courses, county roads,

municipal streets and state highways, and in some instances, such permits are

revocable at the election of the grantor, or, the pipeline may be required to

move its facilities at its own expense. Permits have also been obtained from

railroad companies to cross over or under lands or rights-of-way, many of which

are also revocable at the grantor's election. Some such permits require annual

or other periodic payments. In a few minor cases, property for pipeline purposes

was purchased in fee.

We believe that we have generally satisfactory title to the properties we

own and use in our businesses, subject to liens for current taxes, liens

incident to minor encumbrances, and easements and restrictions which do not

materially detract from the value of such property or the interests in those

properties or the use of such properties in our businesses. We generally do not

own the land on which our pipelines are constructed. Instead, we obtain the

right to construct and operate the pipelines on other people's land for a period

of time. In addition, amounts we have spent during 2006, 2005 and 2004 on

research and development activities were not material.

(d) Financial Information about Geographic Areas

The amount of our assets and operations that are located outside of the

continental United States of America are not material.

<PAGE>

(e) Available Information

We make available free of charge on or through our Internet website, at

www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form

10-Q, current reports on Form 8-K, and amendments to those reports filed or

furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of

1934 as soon as reasonably practicable after we electronically file such

material with, or furnish it to, the Securities and Exchange Commission.

Item 1A. Risk Factors.

You should carefully consider the risks described below, in addition to the

other information contained in this document. Realization of any of the

following risks could have a material adverse effect on our business, financial

condition, cash flows and results of operations. There are also risks associated

with being an owner of common units in a partnership that are different than

being an owner of common stock in a corporation. Investors in our common units

must be aware that the realization of any of those risks could result in a

decline in the trading price of our common units, and they might lose all or

part of their investment.

Risks Related to our Business

Pending Federal Energy Regulatory Commission and California Public

Utilities Commission proceedings seek substantial refunds and reductions in

tariff rates on some of our pipelines. If the proceedings are determined

adversely to us, they could have a material adverse impact on us. Regulators and

shippers on our pipelines have rights to challenge the rates we charge under

certain circumstances prescribed by applicable regulations. Some shippers on our

pipelines have filed complaints with the Federal Energy Regulatory Commission

and California Public Utilities Commission that seek substantial refunds for

alleged overcharges during the years in question and prospective reductions in

the tariff rates on our Pacific operations' pipeline system. We may face

challenges, similar to those described in Note 16 to our consolidated financial

statements included elsewhere in this report, to the rates we receive on our

pipelines in the future. Any successful challenge could adversely and materially

affect our future earnings and cash flows.

Proposed rulemaking by the Federal Energy Regulatory Commission or other

regulatory agencies having jurisdiction over our operations could adversely

impact our income and operations. The rates (which include reservation,

commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers

on our natural gas pipeline systems are subject to regulatory approval and

oversight. 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. Furthermore, regulators

and shippers on our natural gas pipelines 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.

Increased regulatory requirements relating to the integrity of our

pipelines will require us to spend additional money to comply with these

requirements. Through our regulated pipeline subsidiaries, we are subject to

extensive laws and regulations related to pipeline integrity. There are, for

example, federal guidelines for the U.S. Department of Transportation and

pipeline companies in the areas of testing, education, training and

communication. Compliance with laws and regulations requires significant

expenditures. We have increased our capital expenditures to address these

matters and expect to significantly increase these expenditures in the

foreseeable future. Additional laws and regulations that may be enacted in the

future or a new interpretation of existing laws and regulations could

significantly increase the amount of these expenditures.

Cost overruns and delays on our expansion and new build projects could

adversely affect our business. We currently have several major expansion and new

build projects planned or underway, including the approximate $4.4 billion

Rockies Express Pipeline and the 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.

<PAGE>

Our rapid growth may cause difficulties integrating and constructing new

operations, and we may not be able to achieve the expected benefits from any

future acquisitions. Part of our business strategy includes acquiring additional

businesses, expanding existing assets, or constructing new facilities that will

allow us to increase distributions to our unitholders. If we do not successfully

integrate acquisitions, expansions, or newly constructed facilities, we may not

realize anticipated operating advantages and cost savings. The integration of

companies that have previously operated separately involves a number of risks,

including:

o demands on management related to the increase in our size after an

acquisition, an expansion, or a completed construction project;

o the diversion of our management's attention from the management of

daily operations;

o difficulties in implementing or unanticipated costs of accounting,

estimating, reporting and other systems;

o difficulties in the assimilation and retention of necessary employees;

and

o potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that

acquired companies have achieved or might achieve separately. Successful

integration of each acquisition, expansion, or construction project will depend

upon our ability to manage those operations and to eliminate redundant and

excess costs. Because of difficulties in combining and expanding operations, we

may not be able to achieve the cost savings and other size-related benefits that

we hoped to achieve after these acquisitions, which would harm our financial

condition and results of operations.

Our acquisition strategy and expansion programs require access to new

capital. Tightened credit markets or more expensive capital would impair our

ability to grow. Part of our business strategy includes acquiring additional

businesses. We may need new capital to finance these acquisitions. Limitations

on our access to capital will impair our ability to execute this strategy. We

normally fund acquisitions with short-term debt and repay such debt through the

issuance of equity and long-term debt. An inability to access the capital

markets may result in a substantial increase in our leverage and have a

detrimental impact on our credit profile.

Environmental regulation could result in increased operating and capital

costs for us. Our business operations are subject to federal, state and local,

and some foreign laws and regulations relating to environmental protection,

pollution and human health and safety. For example, if an accidental leak,

release or spill of liquid petroleum products, chemicals or other products

occurs from our pipelines or at our storage facilities, we may experience

significant operational disruptions and we may have to pay a significant amount

to clean up the leak, release or spill, pay for government penalties, address

natural resource damage, compensate for human exposure or property damage,

install costly pollution control equipment or a combination of these and other

measures. The resulting costs and liabilities could negatively affect our level

of earnings and cash flows. In addition, emission controls required under the

Federal Clean Air Act and other similar federal and state laws could require

significant capital expenditures at our facilities. The impact on us of

environmental standards or future environmental measures could increase our

costs significantly if environmental laws and regulations become stricter.

In addition, our oil and gas development and production activities are

subject to certain federal, state and local laws and regulations relating to

environmental quality and pollution control. These laws and regulations increase

the costs of these activities and may prevent or delay the commencement or

continuance of a given operation. Specifically, we are subject to laws and

regulations regarding the acquisition of permits before drilling, restrictions

on drilling activities in restricted areas, emissions into the environment,

water discharges, and storage and disposition of hazardous wastes. In addition,

legislation has been enacted which requires well and facility sites to be

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.

The future success of our oil and gas development and production operations

depends in part upon our ability to develop additional oil and gas reserves that

are economically recoverable. The rate of production from oil and natural gas

properties declines as reserves are depleted. Without successful development

activities, the reserves and

<PAGE>

revenues of our CO2 business segment will decline. We may not be able to develop

or acquire additional reserves at an acceptable cost or have necessary financing

for these activities in the future.

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 our CO2

business segment and the carrying value of our oil and natural gas properties

depend to a large degree on prevailing oil and gas prices. Prices for oil and

natural gas are subject to large fluctuations in response to relatively minor

changes in the supply and demand for oil and natural gas, uncertainties within

the market and a variety of other factors beyond our control. These factors

include, among other things, weather conditions and events such as hurricanes in

the United States; the condition of the United States economy; the activities of

the Organization of Petroleum Exporting Countries; governmental regulation;

political stability in the Middle East and elsewhere; the foreign supply of oil

and natural gas; the price of foreign imports; and the availability of

alternative fuel sources.

A sharp decline in the price of natural gas or oil prices would result in a

commensurate reduction in our revenues, income and cash flows from the

production of oil and natural gas and could have a material adverse effect on

the carrying value of our proved reserves. In the event prices fall

substantially, we may not be able to realize a profit from our production and

would operate at a loss. In recent decades, there have been periods of both

worldwide overproduction and underproduction of hydrocarbons and periods of both

increased and relaxed energy conservation efforts. Such conditions have resulted

in periods of excess supply of, and reduced demand for, crude oil on a worldwide

basis and for natural gas on a domestic basis. These periods have been followed

by periods of short supply of, and increased demand for, crude oil and natural

gas. The excess or short supply of crude oil or natural gas has placed pressures

on prices and has resulted in dramatic price fluctuations even during relatively

short periods of seasonal market demand.

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

our income. We currently engage in hedging arrangements to reduce our exposure

to fluctuations in the prices of oil and natural gas. These hedging arrangements

expose us to risk of financial loss in some circumstances, including when

production is less than expected, when the counterparty to the hedging contract

defaults on its contract obligations, or when there is a change in the expected

differential between the underlying price in the hedging agreement and the

actual prices received. In addition, these hedging arrangements may limit the

benefit we would otherwise receive from increases in prices for oil and natural

gas.

The accounting standards regarding hedge accounting are complex, and even

when we engage in hedging transactions (for example, to mitigate our exposure to

unfavorable fluctuations in commodity prices or to balance our exposure to fixed

and floating interest rates) that are effective economically, these transactions

may not be considered effective for accounting purposes. Accordingly, our

financial statements may reflect some volatility due to these hedges, even when

there is no underlying economic impact at that point. In addition, it is not

always possible for us to engage in a hedging transaction that completely

mitigates our exposure to commodity prices. Our financial statements may reflect

a gain or loss arising from an exposure to commodity prices for which we are

unable to enter into a completely effective hedge.

<PAGE>

Competition could ultimately lead to lower levels of profits and lower cash

flow. We face competition from other pipelines and terminals in the same markets

as our assets, as well as from other means of transporting and storing energy

products. For a description of the competitive factors facing our business,

please see Items 1 and 2 "Business and Properties" in this report for more

information.

We do not own approximately 97.5% of the land on which our pipelines are

constructed, and we are subject to the possibility of increased costs to retain

necessary land use. We obtain the right to construct and operate pipelines on

other owners' land for a period of time. If we were to lose these rights or be

required to relocate our pipelines, our business could be affected negatively.

Union Pacific Railroad Company has allowed us to construct and operate a

significant portion of our Pacific operations' pipeline system on railroad

rights-of-way. Union Pacific Railroad Company and its predecessors were given

the right to construct their railroad tracks under federal statutes enacted in

1871 and 1875. The 1871 statute was thought to be an outright grant of ownership

that would continue until the land ceased to be used for railroad purposes. Two

United States Circuit Courts, however, ruled in 1979 and 1980 that railroad

rights-of-way granted under laws similar to the 1871 statute provide only the

right to use the surface of the land for railroad purposes without any right to

the underground portion. If a court were to rule that the 1871 statute does not

permit the use of the underground portion for the operation of a pipeline, we

may be required to obtain permission from the landowners in order to continue to

maintain the pipelines. Approximately 10% of our pipeline assets are located in

the ground underneath railroad rights-of-way.

Whether we have the power of eminent domain for our pipelines varies from

state to state depending upon the type of pipeline--petroleum liquids, natural

gas or carbon dioxide--and the laws of the particular state. Our inability to

exercise the power of eminent domain could negatively affect our business if we

were to lose the right to use or occupy the property on which our pipelines are

located. For the year ended December 31, 2006, all of our right-of-way related

expenses totaled $14.0 million.

Our debt instruments may limit our financial flexibility and increase our

financing costs. The instruments governing our debt contain restrictive

covenants that may prevent us from engaging in certain transactions that we deem

beneficial and that may be beneficial to us. The agreements governing our debt

generally require us to comply with various affirmative and negative covenants,

including the maintenance of certain financial ratios and restrictions on:

o incurring additional debt;

o entering into mergers, consolidations and sales of assets;

o granting liens; and

o entering into sale-leaseback transactions.

The instruments governing any future debt may contain similar or more

restrictive restrictions. Our ability to respond to changes in business and

economic conditions and to obtain additional financing, if needed, may be

restricted.

Because a portion of our debt is subject to variable interest rates, if

interest rates increase, our earnings could be adversely affected. As of

December 31, 2006, we had approximately $3.3 billion of debt, excluding market

value of interest rate swaps, subject to variable interest rates. This amount

included $2.1 billion of long-term fixed rate debt effectively converted to

variable rate debt through the use of interest rate swaps. Should interest rates

increase significantly, our earnings could be adversely affected. For

information on our interest rate risk, see Item 7A "Quantitative and Qualitative

Disclosures About Market Risk--Interest Rate Risk."

Current or future distressed financial condition of customers could have an

adverse impact on us in the event these customers are unable to pay us for the

services we provide. Some of our customers are experiencing, or may experience

in the future, severe financial problems that have had or may have a significant

impact on their creditworthiness. We cannot provide assurance that one or more

of our financially distressed customers will not

<PAGE>

default on their obligations to us or that such a default or defaults will not

have a material adverse effect on our business, financial position, future

results of operations, or future cash flows. Furthermore, the bankruptcy of one

or more of our customers, or some other similar proceeding or liquidity

constraint, might make it unlikely that we would be able to collect all or a

significant portion of amounts owed by the distressed entity or entities. In

addition, such events might force such customers to reduce or curtail their

future use of our products and services, which could have a material adverse

effect on our results of operations and financial condition.

The general uncertainty associated with the current world economic and

political environments in which we exist may adversely impact our financial

performance. Our financial performance is impacted by overall marketplace

spending and demand. We are continuing to assess the effect that terrorism would

have on our businesses and in response, we have increased security with respect

to our assets. Recent federal legislation provides an insurance framework that

should cause current insurers to continue to provide sabotage and terrorism

coverage under standard property insurance policies. Nonetheless, there is no

assurance that adequate sabotage and terrorism insurance will be available at

rates we believe are reasonable throughout 2007. Currently, we do not believe

that the increased cost associated with these measures will have a material

effect on our operating results.

The consummation of the proposed management-led buyout of KMI will result

in substantially more debt at KMI and could have an adverse effect on us, such

as a downgrade in the ratings of our debt securities. On August 28, 2006, KMI

entered into an agreement and plan of merger whereby investors led by Richard D.

Kinder, Chairman and CEO of KMI, would acquire all of the outstanding shares of

KMI (other than shares held by certain stockholders and investors) for $107.50

per share in cash. In connection with the merger, KMI will incur substantially

more debt, which could have an adverse effect on us, such as a downgrade in the

ratings of our debt securities. In response to this proposed transaction,

Standard & Poor's Rating Services has placed our ratings on credit watch pending

resolution of the management buyout proposal. We are not able to predict with

certainty the final outcome of the pending buyout proposal.

Our senior management's attention may be diverted from our daily operations

because of the proposed management-led buyout of KMI and other significant

transactions. The investors in the proposed buyout of KMI include members of

senior management of KMI, most of whom are also senior officers of our general

partner and of KMR. As a result, prior to the closing of the transaction, our

senior management's attention may be diverted from the management of our daily

operations. Similarly, KMI has publicly disclosed that several other significant

transactions are being considered that, if pursued, would require substantial

management time and attention.

Risks Related to Our Common Units

The interests of KMI may differ from our interests and the interests of our

unitholders. KMI indirectly owns all of the stock of our general partner and

elects all of its directors. Our general partner owns all of KMR's voting shares

and elects all of its directors. Furthermore, some of KMR's directors and

officers are also directors and officers of KMI and our general partner and have

fiduciary duties to manage the businesses of KMI in a manner that may not be in

the best interests of our unitholders. KMI has a number of interests that differ

from the interests of our unitholders. As a result, there is a risk that

important business decisions will not be made in the best interests of our

unitholders.

Common unitholders have limited voting rights and limited control. Holders

of common units have only limited voting rights on matters affecting us. Our

general partner manages partnership activities. Under a delegation of control

agreement, our general partner has delegated the management and control of our

and our subsidiaries' business and affairs to KMR. Holders of common units have

no right to elect the general partner on an annual or other ongoing basis. If

the general partner withdraws, however, its successor may be elected by the

holders of a majority of the outstanding common units (excluding units owned by

the departing general partner and its affiliates).

The limited partners may remove the general partner only if:

o the holders of at least 66 2/3% of the outstanding common units,

excluding common units owned by the departing general partner and its

affiliates, vote to remove the general partner;

<PAGE>

o a successor general partner is approved by at least 66 2/3% of the

outstanding common units, excluding common units owned by the

departing general partner and its affiliates; and

o we receive an opinion of counsel opining that the removal would not

result in the loss of limited liability to any limited partner, or the

limited partner of an operating partnership, or cause us or the

operating partnership to be taxed other than as a partnership for

federal income tax purposes.

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

common units held by a person or group that owns 20% or more of the common units

cannot be voted. This limitation does not apply to the general partner and its

affiliates. This provision may:

o discourage a person or group from attempting to remove the general

partner or otherwise change management; and

o reduce the price at which the common units will trade under certain

circumstances. For example, a third party will probably not attempt to

take over our management by making a tender offer for the common units

at a price above their trading market price without removing the

general partner and substituting an affiliate of its own.

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

Our partnership agreement contains language limiting the liability of the

general partner to us or the holders of common units. For example, our

partnership agreement provides that:

o the general partner does not breach any duty to us or the holders of

common units by borrowing funds or approving any borrowing. The

general partner is protected even if the purpose or effect of the

borrowing is to increase incentive distributions to the general

partner;

o the general partner does not breach any duty to us or the holders of

common units by taking any actions consistent with the standards of

reasonable discretion outlined in the definitions of available cash

and cash from operations contained in our partnership agreement; and

o the general partner does not breach any standard of care or duty by

resolving conflicts of interest unless the general partner acts in bad

faith.

Unitholders may have liability to repay distributions. Unitholders will not

be liable for assessments in addition to their initial capital investment in the

common units. Under certain circumstances, however, holders of common units may

have to repay us amounts wrongfully returned or distributed to them. Under

Delaware law, we may not make a distribution to unitholders if the distribution

causes our liabilities to exceed the fair value of our assets. Liabilities to

partners on account of their partnership interests and non-recourse liabilities

are not counted for purposes of determining whether a distribution is permitted.

Delaware law provides that for a period of three years from the date of such a

distribution, a limited partner who receives the distribution and knew at the

time of the distribution that the distribution violated Delaware law will be

liable to the limited partnership for the distribution amount. Under Delaware

law, an assignee who becomes a substituted limited partner of a limited

partnership is liable for the obligations of the assignor to make contributions

to the partnership. However, such an assignee is not obligated for liabilities

unknown to the assignee at the time the assignee became a limited partner if the

liabilities could not be determined from the partnership agreement.

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

law. We conduct our business in a number of states. In some of those states the

limitations on the liability of limited partners for the obligations of a

limited partnership have not been clearly established. The unitholders might be

held liable for the partnership's obligations as if they were a general partner

if:

o a court or government agency determined that we were conducting

business in the state but had not complied with the state's

partnership statute; or

<PAGE>

o unitholders' rights to act together to remove or replace the general

partner or take other actions under our partnership agreement

constitute "control" of our business.

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

units. If at any time the general partner and its affiliates own 80% or more of

the issued and outstanding common units, the general partner will have the right

to purchase all, and only all, of the remaining common units. Because of this

right, a unitholder will have to sell its common units at a time or price that

may be undesirable. The purchase price for such a purchase will be the greater

of:

o the 20-day average trading price for the common units as of the date

five days prior to the date the notice of purchase is mailed; or

o the highest purchase price paid by the general partner or its

affiliates to acquire common units during the prior 90 days.

The general partner can assign this right to its affiliates or to the

partnership.

We may sell additional limited partner interests, diluting existing

interests of unitholders. Our partnership agreement allows the general partner

to cause us to issue additional common units and other equity securities. When

we issue additional equity securities, including additional i-units to KMR when

it issues additional shares, unitholders' proportionate partnership interest in

us will decrease. Such an issuance could negatively affect the amount of cash

distributed to unitholders and the market price of common units. Issuance of

additional common units will also diminish the relative voting strength of the

previously outstanding common units. Our partnership agreement does not limit

the total number of common units or other equity securities we may issue.

The general partner can protect itself against dilution. Whenever we issue

equity securities to any person other than the general partner and its

affiliates, the general partner has the right to purchase additional limited

partnership interests on the same terms. This allows the general partner to

maintain its proportionate partnership interest in us. No other unitholder has a

similar right. Therefore, only the general partner may protect itself against

dilution caused by issuance of additional equity securities.

Our partnership agreement and the KMR limited liability company agreement

restrict or eliminate a number of the fiduciary duties that would otherwise be

owed by our general partner and/or its delegate to our unitholders.

Modifications of state law standards of fiduciary duties may significantly limit

the ability of our unitholders to successfully challenge the actions of our

general partner in the event of a breach of fiduciary duties. These state law

standards include the duties of care and loyalty. The duty of loyalty, in the

absence of a provision in the limited partnership agreement to the contrary,

would generally prohibit our general partner from taking any action or engaging

in any transaction as to which it has a conflict of interest. Our limited

partnership agreement contains provisions that prohibit limited partners from

advancing claims that otherwise might raise issues as to compliance with

fiduciary duties or applicable law. For example, that agreement provides that

the general partner may take into account the interests of parties other than us

in resolving conflicts of interest. It also provides that in the absence of bad

faith by the general partner, the resolution of a conflict by the general

partner will not be a breach of any duty. The provisions relating to the general

partner apply equally to KMR as its delegate. It is not necessary for a limited

partner to sign our limited partnership agreement in order for the limited

partnership agreement to be enforceable against that person.

We could be treated as a corporation for United States income tax purposes.

Our treatment as a corporation would substantially reduce the cash distributions

on the common units that we distribute quarterly. The anticipated benefit of an

investment in our common units depends largely on our treatment as a partnership

for federal income tax purposes. We have not requested, and do not plan to

request, a ruling from the Internal Revenue Service on this or any other matter

affecting us. Current law requires us to derive at least 90% of our annual gross

income from specific activities to continue to be treated as a partnership for

federal income tax purposes. We may not find it possible, regardless of our

efforts, to meet this income requirement or may inadvertently fail to meet this

income requirement. Current law may change so as to cause us to be treated as a

corporation for federal income tax purposes without regard to our sources of

income or otherwise subject us to entity-level taxation.

<PAGE>

If we were to be treated as a corporation for federal income tax purposes,

we would pay federal income tax on our income at the corporate tax rate, which

is currently a maximum of 35% and would pay state income taxes at varying rates.

Under current law, distributions to unitholders would generally be taxed as a

corporate distribution. Because a tax would be imposed upon us as a corporation,

the cash available for distribution to a unitholder would be substantially

reduced. Treatment of us as a corporation would cause a substantial reduction in

the value of our units.

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 us as an entity, the cash available for distribution

to our unitholders would be reduced.

Risks Related to Ownership of Our Common Units if We or KMI Default on Debt

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

sell assets. If we default on any of our debt, the lenders will have the right

to sue us for non-payment. Such an action could cause an investment loss and

cause negative tax consequences for unitholders through the realization of

taxable income by unitholders without a corresponding cash distribution.

Likewise, if we were to dispose of assets and realize a taxable gain while there

is substantial debt outstanding and proceeds of the sale were applied to the

debt, unitholders could have increased taxable income without a corresponding

cash distribution.

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

owns all of the outstanding capital stock of the general partner. If KMI

defaults on its debt, its lenders could acquire control of the general partner.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

See Note 16 of the notes to our consolidated financial statements included

elsewhere in this report.

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

There were no matters submitted to a vote of our unitholders during the

fourth quarter of 2006.

<PAGE>

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities.

The following table sets forth, for the periods indicated, the high and low

sale prices per common unit, as reported on the New York Stock Exchange, the

principal market in which our common units are traded, the amount of cash

distributions declared per common and Class B unit, and the fractional i-unit

distribution declared per i-unit.

Price Range

------------------

Cash i-unit

High Low Distributions Distributions

---- --- ------------- -------------

2006

First Quarter $ 56.22 $ 44.70 $ 0.8100 0.018566

Second Quarter 48.80 43.62 0.8100 0.018860

Third Quarter. 46.53 42.80 0.8100 0.018981

Fourth Quarter 48.98 43.01 0.8300 0.016919

2005

First Quarter $ 47.55 $ 42.77 $ 0.7600 0.017482

Second Quarter 51.49 45.22 0.7800 0.016210

Third Quarter. 55.20 49.72 0.7900 0.016360

Fourth Quarter 53.56 47.21 0.8000 0.017217

Distribution information is for distributions declared with respect to that

quarter. The declared distributions were paid within 45 days after the end of

the quarter. We currently expect to declare cash distributions of at least $3.44

per unit for 2007 and further, we expect that we will continue to be able to

grow our distribution per unit at about 8% per year over the long-term assuming

no adverse change in our operations, economic conditions and other factors.

However, no assurance can be given that we will be able to achieve this level of

distribution, and our expectation does not take into account any capital costs

associated with financing the payment of reparations sought by shippers on our

Pacific operations' interstate pipelines.

As of February 1, 2007, there were approximately 190,230 beneficial owners

of our common units, one holder of our Class B units and one holder of our

i-units.

For information on our equity compensation plans, see Item 12 "Security

Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters--Equity Compensation Plan Information".

Effective December 1, 2006, we issued 34,627 common units as part of the

purchase price for all of the membership interests in Devco USA L.L.C. Our total

purchase price for Devco was 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 units were issued to a single accredited investor in a

transaction not involving a public offering, exempt from registration pursuant

to Section 4(2) of the Securities Act of 1933.

We did not repurchase any units during 2006.

<PAGE>

Item 6. Selected Financial Data

The following tables set forth, for the periods and at the dates indicated,

our summary historical financial and operating data. The table is derived from

our consolidated financial statements and notes thereto, and should be read in

conjunction with those audited financial statements. See also Item 7

"Management's Discussion and Analysis of Financial Condition and Results of

Operations" in this report for more information.

<TABLE>

Year Ended December 31,

----------------------------------------------------------------

2006(5) 2005(6) 2004(7) 2003(8) 2002(9)

---------- ----------- ----------- ----------- -----------

(In thousands, except per unit and ratio data)

Income and Cash Flow Data:

Revenues............................................ $ 8,954,583 $ 9,787,128 $ 7,932,861 $ 6,624,322 $ 4,237,057

Gas purchases and other costs of sales.............. 5,990,963 7,167,414 5,767,169 4,880,118 2,704,295

Operations and maintenance.......................... 769,514 747,363 499,714 397,723 376,479

Fuel and power...................................... 216,222 183,458 151,480 108,112 86,413

Depreciation, depletion and amortization............ 413,725 349,827 288,626 219,032 172,041

General and administrative.......................... 219,575 216,706 170,507 150,435 122,205

Taxes, other than income taxes...................... 118,756 108,838 81,369 62,213 51,326

Other expense (income).............................. (30,306) -- -- -- --

------------ ------------ ------------ ------------ ------------

Operating income.................................. 1,256,134 1,013,522 973,996 806,689 724,298

Other income/(expense):

Earnings from equity investments.................... 76,170 91,660 83,190 92,199 89,258

Amortization of excess cost of equity investments... (5,664) (5,644) (5,575) (5,575) (5,575)

Interest, net....................................... (331,499) (258,861) (192,882) (181,357) (176,460)

Other, net.......................................... 11,065 3,273 2,254 7,601 1,698

Minority interest................................... (15,015) (7,262) (9,679) (9,054) (9,559)

Income tax provision................................ (19,048) (24,461) (19,726) (16,631) (15,283)

------------ ------------ ------------ ------------ ------------

Income before cumulative effect of a change in

accounting principle............................. 972,143 812,227 831,578 693,872 608,377

Cumulative effect of a change in accounting principle -- -- -- 3,465 --

------------ ------------ ------------ ------------ ------------

Net income........................................ $ 972,143 $ 812,227 $ 831,578 $ 697,337 $ 608,377

Less: General Partner's interest in net income.... (512,967) (477,300) (395,092) (326,524) (270,816)

------------ ------------ ------------ ------------ ------------

Limited Partners' interest in net income.......... $ 459,176 $ 334,927 $ 436,486 $ 370,813 $ 337,561

============ ============ ============ ============ ============

Basic and Diluted Limited Partners' Net Income per

unit:

Income before cumulative effect of a change in

accounting principle(1).......................... $ 2.04 $ 1.58 $ 2.22 $ 1.98 $ 1.96

Cumulative effect of a change in accounting principle -- -- -- 0.02 --

------------ ------------ ------------ ------------ ------------

Net income.......................................... $ 2.04 $ 1.58 $ 2.22 $ 2.00 $ 1.96

============ ============ ============ ============ ============

Per unit cash distribution declared(2).............. $ 3.26 $ 3.13 $ 2.87 $ 2.63 $ 2.435

Ratio of earnings to fixed charges(3)............... 3.63 3.76 4.91 4.77 4.37

Additions to property, plant and equipment.......... $ 1,058,265 $ 863,056 $ 747,262 $ 576,979 $ 542,235

Balance Sheet Data (at end of period):

Net property, plant and equipment.................. $ 9,445,471 $ 8,864,584 $ 8,168,680 $ 7,091,558 $ 6,244,242

Total assets........................................ $12,246,394 $11,923,462 $10,552,942 $ 9,139,182 $ 8,353,576

Long-term debt(4)................................... $ 4,384,332 $ 5,220,887 $ 4,722,410 $ 4,316,678 $ 3,659,533

Partners' capital................................... $ 4,021,653 $ 3,613,740 $ 3,896,520 $ 3,510,927 $ 3,415,929

------------------

</TABLE>

(1) Represents income before cumulative effect of a change in accounting

principle per unit. Basic Limited Partners' income per unit before

cumulative effect of a change in accounting principle was computed by

dividing the interest of our unitholders in income before cumulative effect

of a change in accounting principle by the weighted average number of units

outstanding during the period. Diluted Limited Partners' net income per

unit reflects the maximum potential dilution that could occur if units

whose issuance depends on the market price of the units at a future date

were considered outstanding, or if, by application of the treasury stock

method, options to issue units were exercised, both of which would result

in the issuance of additional units that would then share in our net

income.

(2) Represents the amount of cash distributions declared with respect to that

year.

(3) For the purpose of computing the ratio of earnings to fixed charges,

earnings are defined as income before income taxes and cumulative effect of

a change in accounting principle, and before minority interest in

consolidated subsidiaries, equity earnings (including amortization of

excess cost of equity investments) and unamortized capitalized interest,

plus fixed

<PAGE>

charges and distributed income of equity investees. Fixed charges are

defined as the sum of interest on all indebtedness (excluding capitalized

interest), amortization of debt issuance costs and that portion of rental

expense which we believe to be representative of an interest factor.

(4) Excludes market value of interest rate swaps. Increases to long-term debt

for market value of interest rate swaps totaled $42,630 as of December 31,

2006, $98,469 as of December 31, 2005, $130,153 as of December 31, 2004,

$121,464 as of December 31, 2003, and $166,956 as of December 31, 2002.

(5) Includes results of operations for the oil and gas properties acquired from

Journey Acquisition-I, L.P. and Journey 2000, L.P., the terminal assets and

operations acquired from A&L Trucking, L.P. and U.S. Development Group,

Transload Services, LLC, and Devco USA L.L.C. since effective dates of

acquisition. The April 5, 2006 acquisition of the Journey oil and gas

properties were made effective March 1, 2006. The assets and operations

acquired from A&L Trucking and U.S. Development Group were acquired in

three separate transactions in April 2006. We acquired all of the

membership interests in Transload Services, LLC effective November 20,

2006, and we acquired all of the membership interests in Devco USA L.L.C.

effective December 1, 2006. We also acquired a 66 2/3% ownership interest

in Entrega Pipeline LLC effective February 23, 2006, however, our earnings

were not materially impacted during 2006 due to the fact that regulatory

accounting provisions required capitalization of revenues and expenses

until the second segment of the Entrega Pipeline is complete and

in-service.

(6) Includes results of operations for the 64.5% interest in the Claytonville

unit, the seven bulk terminal operations acquired from Trans-Global

Solutions, Inc., the Kinder Morgan Staten Island terminal, the terminal

facilities located in Hawesville, Kentucky and Blytheville, Arkansas,

General Stevedores, L.P., the North Dayton natural gas storage facility,

the Kinder Morgan Blackhawk terminal, the terminal repair shop acquired

from Trans-Global Solutions, Inc., and the terminal assets acquired from

Allied Terminals, Inc. since effective dates of acquisition. We acquired

the 64.5% interest in the Claytonville unit effective January 31, 2005. We

acquired the seven bulk terminal operations from Trans-Global Solutions,

Inc. effective April 29, 2005. The Kinder Morgan Staten Island terminal,

the Hawesville, Kentucky terminal and the Blytheville, Arkansas terminal

were each acquired separately in July 2005. We acquired all of the

partnership interests in General Stevedores, L.P. effective July 31, 2005.

We acquired the North Dayton natural gas storage facility effective August

1, 2005. We acquired the Kinder Morgan Blackhawk terminal in August 2005

and the terminal repair shop in September 2005. We acquired the terminal

assets from Allied Terminals, Inc. effective November 4, 2005.

(7) Includes results of operations for the seven refined petroleum products

terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an

additional 5% interest in the Cochin Pipeline System, Kinder Morgan River

Terminals LLC and its consolidated subsidiaries, TransColorado Gas

Transmission Company, interests in nine refined petroleum products

terminals acquired from Charter Terminal Company and Charter-Triad

Terminals, LLC, and the Kinder Morgan Fairless Hills terminal since

effective dates of acquisition. We acquired the seven refined petroleum

products terminals from ExxonMobil effective March 9, 2004. We acquired

Kinder Morgan Wink Pipeline, L.P. effective August 31, 2004. The additional

interest in Cochin was acquired effective October 1, 2004. We acquired

Kinder Morgan River Terminals LLC and its consolidated subsidiaries

effective October 6, 2004. We acquired TransColorado effective November 1,

2004, the interests in the nine Charter Terminal Company and Charter-Triad

Terminals, LLC refined petroleum products terminals effective November 5,

2004, and the Kinder Morgan Fairless Hills terminal effective December 1,

2004.

(8) Includes results of operations for the bulk terminal operations acquired

from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC

unit, the five refined petroleum products terminals acquired from Shell,

the additional 42.5% interest in the Yates field unit, the crude oil

gathering operations surrounding the Yates field unit, an additional 65%

interest in the Pecos Carbon Dioxide Company, the remaining approximate 32%

interest in MidTex Gas Storage Company, LLP, the seven refined petroleum

products terminals acquired from ConocoPhillips and two bulk terminal

facilities located in Tampa, Florida since dates of acquisition. We

acquired certain bulk terminal operations from M.J. Rudolph effective

January 1, 2003. The additional 12.75% interest in SACROC was acquired

effective June 1, 2003. The five refined petroleum products terminals were

acquired effective October 1, 2003. The additional 42.5% interest in the

Yates field unit, the Yates gathering system and the additional 65%

interest in Pecos Carbon Dioxide Company were acquired effective November

1, 2003. The additional 32% ownership interest in MidTex was acquired

November 1, 2003. The seven refined petroleum products terminals were

acquired December 11, 2003, and the two bulk terminal facilities located in

Tampa, Florida were acquired effective December 10 and 23, 2003.

(9) Includes results of operations for the additional 10% interest in the

Cochin Pipeline System, Kinder Morgan Materials Services LLC (formerly

Laser Materials Services LLC), the 66 2/3% interest in International Marine

Terminals, Tejas Gas, LLC, Milwaukee Bagging Operations, the remaining 33

1/3% interest in Trailblazer Pipeline Company, the Owensboro Gateway

Terminal and IC Terminal Holdings Company and its consolidated subsidiaries

since dates of acquisitions. The additional interest in Cochin was acquired

effective December 31, 2001. Kinder Morgan Materials Services LLC was

acquired effective January 1, 2002. We acquired a 33 1/3% interest in

International Marine Terminals effective January 1, 2002 and an additional

33 1/3% interest effective February 1, 2002. Tejas Gas, LLC was acquired

effective January 31,

<PAGE>

2002. The Milwaukee Bagging Operations were acquired effective May 1, 2002.

The remaining interest in Trailblazer was acquired effective May 6, 2002.

The Owensboro Gateway Terminal and IC Terminal Holdings Company and its

subsidiaries were acquired effective September 1, 2002.

Item 7. Management's Discussion and Analysis of Financial Condition and

Results of Operations.

The following discussion and analysis of our financial condition and

results of operations provides you with a narrative on our financial results. It

contains a discussion and analysis of the results of operations for each segment

of our business, followed by a discussion and analysis of our financial

condition. The following discussion and analysis is based on our consolidated

financial statements, which are included elsewhere in this report and were

prepared in accordance with accounting principles generally accepted in the

United States of America. You should read the following discussion and analysis

in conjunction with our consolidated financial statements.

Additional sections in this report which should be helpful to your reading

of our discussion and analysis include the following:

o a description of our business strategy found in Items 1 and 2

"Business and Properties - Business Strategy";

o a description of developments during 2006, found in Items 1 and 2

"Business and Properties - Recent Developments"; and

o a description of risk factors affecting us and our business, found in

Item 1A "Risk Factors."

We begin with a discussion of our Critical Accounting Polices and

Estimates, those areas that are both very important to the portrayal of our

financial condition and results and which require our management's most

difficult, subjective or complex judgments, often as a result of the need to

make estimates about the effect of matters that are inherently uncertain.

Critical Accounting Policies and Estimates

Accounting standards require information in financial statements about the

risks and uncertainties inherent in significant estimates, and the application

of generally accepted accounting principles involves the exercise of varying

degrees of judgment. Certain amounts included in or affecting our consolidated

financial statements and related disclosures must be estimated, requiring us to

make certain assumptions with respect to values or conditions that cannot be

known with certainty at the time the financial statements are prepared. These

estimates and assumptions affect the amounts we report for our assets and

liabilities, our revenues and expenses during the reporting period, and our

disclosure of contingent assets and liabilities at the date of our financial

statements.

We routinely evaluate these estimates, utilizing historical experience,

consultation with experts and other methods we consider reasonable in the

particular circumstances. Nevertheless, actual results may differ significantly

from our estimates. Any effects on our business, financial position or results

of operations resulting from revisions to these estimates are recorded in the

period in which the facts that give rise to the revision become known.

In preparing our consolidated financial statements and related disclosures,

examples of certain areas that require more judgment relative to others include

our use of estimates in determining:

o the economic useful lives of our assets;

o the fair values used to allocate purchase price and to determine

possible asset impairment charges;

o reserves for environmental claims, legal fees, transportation rate

cases and other litigation liabilities;

o provisions for uncollectible accounts receivables;

<PAGE>

o exposures under contractual indemnifications; and

o various other recorded or disclosed amounts.

We believe that certain accounting policies are of more significance in our

consolidated financial statement preparation process than others, which policies

are discussed following.

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 steps involved in the process of managing our environmental reporting

include:

o identifying environmental regulatory issues that may affect us with

respect to potential clean-up liabilities, and the necessary level of

investigation in order to determine the potential cost associated with

environmental exposures;

o completing a materiality analysis to determine the reporting necessary

for each environmental issue; and

o evaluating alternatives to properly manage our environmental

liabilities going forward, including items such as environmental

insurance to help limit estimated costs, thereby assuring our

unitholders that the volatility often associated with environmental

estimates will not impair the value of their holdings.

Our recording of our environmental accruals often coincides with our

completion of a feasibility study or our commitment to a formal plan of action,

but generally, we recognize and/or adjust our environmental liabilities

following routine reviews of potential environmental issues and claims that

could impact our assets or operations. In both December 2005 and December 2004,

after thorough reviews of any potential environmental issues and claims, we

trued up (adjusted) our year-end environmental liabilities to reflect revisions

to previously estimated costs. The adjustments, described more fully below,

resulted in increases in environmental expenses.

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 us and Plantation Pipe Line Company). These supplemental

environmental liability adjustments were recorded pursuant to our management's

requirement to recognize contingent environmental liabilities whenever the

associated environmental issue is likely to occur and the amount of our

liability can be reasonably estimated. In making these liability estimations, we

considered the effect of environmental compliance, pending legal actions against

us, and potential third-party liability claims.

As a result, in 2006, we recorded a combined $35.4 million decrease in

earnings associated with total environmental liability adjustments, including a

$17.9 million decrease in earnings associated with supplemental liability

adjustments. The total environmental expense adjustments (including our share of

environmental expense associated with liability adjustments recognized by

Plantation Pipe Line Company) included a $4.1 million increase in our estimated

environmental receivables and reimbursables, a $3.5 million decrease in our

equity investments, a $34.5 million increase in our overall accrued

environmental and related claim liabilities, and a $1.5 million increase in our

accrued expense liabilities.

The $17.9 million decrease in earnings related to supplemental

environmental liability adjustments resulted in a $16.4 million increase in

expense to our Products Pipelines business segment and a $1.5 million increase

in expense to our Natural Gas Pipelines business segment. It consisted of a

$14.9 million expense recorded within "Operations

<PAGE>

and maintenance," a $4.9 million expense recorded within "Earnings from equity

investments," and a $1.9 million reduction in expense recorded within "Income

Taxes" in our accompanying consolidated statement of income for 2006.

Our 2005 environmental liability adjustments resulted from both revisions

to previously estimated costs and from the necessity of properly adjusting our

environmental expenses and accrued liabilities between our reportable business

segments, and combined, the adjustments resulted in a $23.3 million increase in

environmental expense that primarily affected our Products Pipelines and

Terminals business segments. The $23.3 million increase in environmental expense

resulted in a $19.6 million increase in expense to our Products Pipelines

business segment, a $3.5 million increase in expense to our Terminals business

segment, a $0.3 million increase in expense to our CO2 business segment, and a

$0.1 million decrease in expense to our Natural Gas Pipelines business segment.

The adjustment included an $8.7 million increase in our estimated environmental

receivables and reimbursables and a $32.0 million increase in our overall

accrued environmental and related claim liabilities. We included the additional

$23.3 million expense within "Operations and maintenance" in our accompanying

consolidated statement of income for 2005.

In 2004, we recognized a $0.2 million increase in environmental expenses

and an associated $0.1 million increase in deferred income tax expense resulting

from changes to previous estimates. The $0.3 million expense item, including

taxes, resulted from the necessity of properly adjusting our environmental

expenses, liabilities and receivables between our four reportable business

segments. The net impact of the $0.3 million expense item resulted in a $30.6

million increase in expense to our Products Pipelines business segment, a $7.6

million decrease in expense to our Natural Gas Pipelines business segment, a

$4.1 million decrease in expense to our CO2 business segment, and an $18.6

million decrease in expense to our Terminals business segment. The adjustment

included an $18.9 million increase in our estimated environmental receivables

and reimbursables and a $19.1 million increase in our overall accrued

environmental and related claim liabilities. We included the additional $0.2

million environmental expense within "Other, net" in our accompanying

consolidated statement of income for 2004.

For more information on our environmental disclosures, see Note 16 to our

consolidated financial statements included elsewhere in this report.

Legal Matters

We are subject to litigation and regulatory proceedings as a result of our

business operations and transactions. We utilize both internal and external

counsel in evaluating our potential exposure to adverse outcomes from orders,

judgments or settlements. To the extent that actual outcomes differ from our

estimates, or additional facts and circumstances cause us to revise our

estimates, our earnings will be affected. 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 our Pacific

operations' pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by our

Pacific operations' pipeline systems are subject to certain proceedings at the

FERC involving shippers' complaints regarding the interstate rates, as well as

practices and the jurisdictional nature of certain facilities and services.

Generally, the interstate rates on our Pacific operations' pipeline systems are

"grandfathered" under the Energy Policy Act of 1992 unless "substantially

changed circumstances" are found to exist. To the extent "substantially changed

circumstances" are found to exist, our Pacific operations may be subject to

substantial exposure under these FERC complaints and could, therefore, owe

reparations and/or refunds to complainants as mandated by FERC or the United

States' judicial system.

In December 2005, we recorded an accrual of $105.0 million for an expense

attributable to an increase in our reserves related to our rate case liability,

and we included this amount within "Operations and maintenance" in our

accompanying consolidated statement of income for 2005. 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

FERC (in 2003, we paid transportation rate reparation and refund payments in the

amount of $44.9 million as mandated by the FERC); and (iii) the decision of our

management as to how we intended to respond to the complaints, which included

the compliance filing we submitted to the FERC on March 7, 2006.

<PAGE>

In accordance with the FERC's December 2005 Order and February 2006 Order

on Rehearing, rate reductions were implemented 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 our Pacific operations in the FERC Docket Nos. OR92-8, OR96-2, and IS05-230

proceedings.

We 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 February 2006 FERC Orders, and subject to the ultimate

resolution of these issues in our compliance filings and subsequent judicial

appeals, we now expect the total annual impact will be less than 15 cents per

unit. We estimate that the actual, partial year impact on 2006 distributable

cash flow was approximately $15.7 million. As of December 31, 2006, our total

reserve related to various claims from lawsuits arising from our Pacific

operations' pipeline transportation rates amounted to $108.3 million.

In addition, in the third quarter of 2006, we made refund payments of $19.1

million to certain shippers on our Pacific operations' pipelines and we reduced

our 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 our Pacific operations'

Watson Station, located in Carson, California.

For more information on our Pacific operations' regulatory proceedings, see

Note 16 to our consolidated financial statements included elsewhere in this

report.

Intangible Assets

Intangible assets are those assets which provide future economic benefit

but have no physical substance. We account for our intangible assets according

to the provisions of Statement of Financial Accounting Standards No. 141,

"Business Combinations" and Statement of Financial Accounting Standards No. 142,

"Goodwill and Other Intangible Assets." These accounting pronouncements

introduced the concept of indefinite life intangible assets and provided that

all identifiable intangible assets having indefinite useful economic lives,

including goodwill, will not be subject to regular periodic amortization. Such

assets are not to be amortized until their lives are determined to be finite.

Instead, the carrying amount of a recognized intangible asset with an indefinite

useful life must be tested for impairment annually or on an interim basis if

events or circumstances indicate that the fair value of the asset has decreased

below its carrying value. We have selected an impairment measurement test date

of January 1 of each year, and we have determined that our goodwill was not

impaired as of January 1, 2007. As of January 1, 2007, our goodwill was $829.0

million.

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 our accompanying consolidated balance sheets. As of

December 31, 2006 and 2005, these intangibles totaled $213.2 million and $217.0

million, respectively.

Estimated Net Recoverable Quantities of Oil and Gas

We use the successful efforts method of accounting for our oil and gas

producing activities. The successful efforts method inherently relies on the

estimation of proved reserves, both developed and undeveloped. The existence and

the estimated amount of proved reserves affect, among other things, whether

certain costs are 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.

<PAGE>

Hedging Activities

We engage in a hedging program that utilizes derivative contracts to

mitigate (offset) our exposure to fluctuations in commodity prices and to

balance our exposure to fixed and floating interest rates, and we believe that

these hedges are generally effective in realizing these objectives. However, the

accounting standards regarding hedge accounting are complex, and even when we

engage in hedging transactions that are effective economically, these

transactions may not be considered effective for accounting purposes.

According to the provisions of current accounting standards, to be

considered effective, changes in the value of a derivative contract or its

resulting cash flows must substantially offset changes in the value or cash

flows of the item being hedged. A perfectly effective hedge is one in which

changes in the value of the derivative contract exactly offset changes in the

value of the hedged item or expected cash flow of the future transactions in

reporting periods covered by the derivative contract. The ineffective portion of

the gain or loss and any component excluded from the computation of the

effectiveness of the derivative contract must be reported in earnings

immediately; accordingly, our financial statements may reflect some volatility

due to these hedges.

In addition, it is not always possible for us to engage in a hedging

transaction that completely mitigates our exposure to unfavorable changes in

commodity prices. For example, when we purchase a commodity at one location and

sell it at another, we may be unable to hedge completely our exposure to a

differential in the price of the product between these two locations. Even when

we cannot enter into a completely effective hedge, we often enter into hedges

that are not completely effective in those instances where we believe to do so

would be better than not hedging at all, but due to the fact that the part of

the hedging transaction that is not effective in offsetting undesired changes in

commodity prices (the ineffective portion) is required to be recognized

currently in earnings, our financial statements may reflect a gain or loss

arising from an exposure to commodity prices for which we are unable to enter

into a completely effective hedge.

Results of Operations

Our business model is built to support two principal components:

o helping customers by providing energy, bulk commodity and liquids

products transportation, storage and distribution; and

o creating long-term value for our unitholders.

To achieve these objectives, we focus on providing fee-based services to

customers from a business portfolio consisting of energy-related pipelines, bulk

and liquids terminal facilities, and carbon dioxide and petroleum reserves. Our

reportable business segments are based on the way our management organizes our

enterprise, and each of our four segments represents a component of our

enterprise that engages in a separate business activity and for which discrete

financial information is available.

Consolidated

<TABLE>

Year Ended December 31,

---------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands)

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity investments

Products Pipelines.................................................. $ 491,150 $ 370,052 $ 444,865

Natural Gas Pipelines............................................... 574,799 500,324 418,261

CO2................................................................. 488,170 470,887 357,636

Terminals........................................................... 408,133 314,606 281,738

----------- ----------- -----------

Segment earnings before depreciation, depletion and

amortization of excess cost of equity investments(a)............ 1,962,252 1,655,869 1,502,500

Depreciation, depletion and amortization expense.................... (413,725) (349,827) (288,626)

Amortization of excess cost of investments.......................... (5,664) (5,644) (5,575)

Interest and corporate administrative expenses(b)................... (570,720) (488,171) (376,721)

----------- ----------- -----------

Net income........................................................ $ 972,143 $ 812,227 $ 831,578

=========== =========== ===========

</TABLE>

<PAGE>

-----------------

(a) Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses and other

expense (income). Operating expenses include natural gas purchases and

other costs of sales, operations and maintenance expenses, fuel and power

expenses and taxes, other than income taxes.

2006 amount includes supplemental environmental liability adjustments

resulting in a $16,448 increase in expense to our Products Pipelines

business segment and a $1,500 increase in expense to our Natural Gas

Pipelines business segment. Also includes a $15,114 gain to our Natural Gas

Pipelines business segment from the combined sale of our Douglas natural

gas gathering system and Painter Unit fractionation facility, an $11,275

net increase in income to our Terminals business segment from the combined

effect of a property casualty insurance gain and incremental repair and

clean-up expenses (both associated with the 2005 hurricane season), a

$6,244 reduction in expense to our Natural Gas Pipelines business segment

due to the release of a reserve related to a natural gas pipeline contract

obligation, a $5,700 increase in income to our Products Pipelines business

segment from the settlement of transmix processing contracts, and a $1,819

decrease in revenues to our CO2 business segment related to a loss on

derivative contracts used to hedge forecasted crude oil sales.

2005 amount includes a rate case liability adjustment resulting in a

$105,000 expense to our Products Pipelines business segment, a $13,691

increase in expense to our Products Pipelines business segment resulting

from a North System liquids inventory reconciliation adjustment, and

environmental liability adjustments resulting in a $19,600 expense to our

Products Pipelines business segment, an $89 reduction in expense to our

Natural Gas Pipelines business segment, a $298 increase in expense to our

CO2 business segment and a $3,535 increase in expense to our Terminals

business segment.

2004 amount includes environmental liability adjustments resulting in a

$30,611 increase in expense to our Products Pipelines business segment, a

$7,602 reduction in expense to our Natural Gas Pipelines business segment,

a $4,126 reduction in expense to our CO2 business segment and an $18,571

reduction in expense to our Terminals business segment.

(b) Includes unallocated interest income, interest and debt expense, general

and administrative expenses (including unallocated litigation and

environmental expenses), minority interest expense and loss from early

extinguishment of debt (2004 only).

Driven by strong financial results from natural gas sales, storage and

processing activities, and by incremental earnings from both dry-bulk product

and petroleum liquids terminal operations, we achieved a record level of net

income in 2006. For the year 2006, our net income was $972.1 million ($2.04 per

diluted unit) on revenues of $8,954.6 million. This compares with net income of

$812.2 million ($1.58 per diluted unit) on revenues of $9,787.1 million in 2005,

and net income of $831.6 million ($2.22 per diluted unit) on revenues of

$7,932.9 million in 2004.

Segment earnings before depreciation, depletion and amortization expenses

Because our partnership agreement requires us to distribute 100% of our

available cash to our partners on a quarterly basis (available cash consists

primarily of all our cash receipts, less cash disbursements and changes in

reserves), we consider each period's earnings before all non-cash depreciation,

depletion and amortization expenses, including amortization of excess cost of

equity investments, to be an important measure of our success in maximizing

returns to our partners. We also use segment earnings before depreciation,

depletion and amortization expenses (defined in the table above) internally as a

measure of profit and loss used for evaluating segment performance and for

deciding how to allocate resources to our four reportable business segments.

Combined, our four business segments reported earnings before depreciation,

depletion and amortization of $1,962.3 million in 2006, $1,655.9 million in 2005

and $1,502.5 million in 2004.

Both the $306.4 million (19%) increase in total segment earnings before

depreciation, depletion, and amortization in 2006 compared to 2005, and the

$153.4 million (10%) increase in 2005 compared to 2004 were attributable to

internal growth and expansion and to incremental contributions from assets and

operations acquired since the end of 2004. Combined, the net effect of the

certain other items described in footnote (a) in the table above resulted in a

$160.6 million (8%) increase in total segment earnings before depreciation,

depletion and amortization expenses in 2006 relative to 2005, and a $141.7

million (8%) decrease in segment earnings in 2005 relative to 2004. The

remaining increases of $145.8 million (3%) and $295.1 million (20%),

respectively, in total segment earnings before depreciation, depletion and

amortization in 2006 and 2005, relative to prior years, consisted of the

following:

<PAGE>

o increases of $78.7 million (4%) and $55.0 million (21%), respectively,

from our Terminals segment--primarily driven by both higher revenues

earned from transporting and storing higher volumes of petroleum and

petrochemical-related liquids and dry-bulk material products, and

incremental earnings from the impact of completed internal expansion

projects and acquired terminal operations since the end of 2004;

o increases of $54.7 million (11%) and $89.6 million (22%),

respectively, from our Natural Gas Pipelines segment--largely due to

improved sales margins on renewal and incremental natural gas sales

contracts, higher earnings from natural gas storage, gathering and

treating operations, and in 2006, to higher earnings from natural gas

processing activities;

o increases of $18.8 million (4%) and $117.7 million (33%),

respectively, from our CO2 segment--primarily due to higher sales of

carbon dioxide, crude oil, and natural gas processing plant liquids

products at higher average prices, and to higher revenues from carbon

dioxide transportation and related services associated with enhanced

crude oil recovery operations; and

o a decrease of $6.4 million (1%) and an increase of $32.8 million (7%),

respectively, from our Products Pipelines segment. As described more

fully below in "--Products Pipelines," the decrease in 2006 compared

to 2005 was largely related to incremental pipeline maintenance

expenses related to a change (beginning in the third quarter of 2006)

that transferred certain pipeline integrity management costs from

sustaining capital expenditures to expense. The increase in segment

earnings before depreciation, depletion and amortization in 2005

compared to 2004 was mainly due to higher revenues from deliveries of

refined petroleum products and natural gas liquids, higher revenues

from refined products terminal operations, and to incremental earnings

from the acquisition of Southeast terminal operations acquired in

2004;

While it is difficult to predict change in demand for energy

transportation, as well as future prices for energy commodity products and

overall economic trends, going forward, we anticipate a 12% increase in our

total segment earnings before depreciation, depletion, and amortization expenses

in 2007 compared to 2006. The key to our anticipated growth in 2007 will be the

continued expansion of our businesses, principally through capital investments

that will add throughput capacity to our refined products and natural gas

pipeline systems, increase our natural gas storage capacity, expand and enhance

our terminal services, and add infrastructure to our crude oil development and

carbon dioxide flooding operations.

Additionally, we declared a cash distribution of $0.83 per unit for the

fourth quarter of 2006 (an annualized rate of $3.32 per unit). This distribution

was 4% higher than the $0.80 per unit distribution we made for the fourth

quarter of 2005, and 12% higher than the $0.74 per unit distribution we made for

the fourth quarter of 2004. We expect to declare cash distributions of at least

$3.44 per unit for 2007; however, no assurance can be given that we will be able

to achieve this level of distribution, and our expectation does not take into

account any capital costs associated with financing the payment of reparations

sought by shippers on our Pacific operations' interstate pipelines. Our general

partner and our common and Class B unitholders receive quarterly distributions

in cash, while KMR, the sole owner of our i-units, receives quarterly

distributions in additional i-units. The value of the quarterly per-share

distribution of i-units is based on the value of the quarterly per-share cash

distribution made to our common and Class B unitholders.

Products Pipelines

<TABLE>

Year Ended December 31,

-------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands, except operating statistics)

Revenues............................................................. $ 776,268 $ 711,886 $ 645,249

Operating expenses(including adjustments)(a)......................... (308,296) (366,048) (222,036)

Earnings from equity investments(b).................................. 16,336 28,446 29,050

Interest income and Other, net- income (expense)(c).................. 12,017 6,111 4,677

Income taxes(d)...................................................... (5,175) (10,343) (12,075)

---------- ----------- -----------

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity investments..... 491,150 370,052 444,865

Depreciation, depletion and amortization expense..................... (82,888) (79,199) (71,263)

Amortization of excess cost of equity investments.................... (3,362) (3,350) (3,281)

---------- ----------- -----------

Segment earnings................................................... $ 404,900 $ 287,503 $ 370,321

========== =========== ===========

<PAGE>

Year Ended December 31,

-------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands, except operating statistics)

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

========== =========== ===========

</TABLE>

--------------

(a) 2006 amount includes expense of $13,458 associated with supplemental

environmental liability adjustments. 2005 amount includes expense of

$19,600 associated with environmental liability adjustments, expense of

$105,000 associated with a rate case liability adjustment, and expense of

$13,691 associated with a North System liquids inventory reconciliation

adjustment. 2004 amount includes expense of $30,611 associated with

environmental liability adjustments.

(b) 2006 amount includes expense of $4,861 associated with environmental

liability adjustments on Plantation Pipe Line Company.

processing contracts.

(d) 2006 amount includes a decrease in expense of $1,871 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.

Our Products Pipelines segment's primary businesses include transporting

refined petroleum products and natural gas liquids through pipelines and

operating liquid petroleum products terminals and petroleum pipeline transmix

processing facilities. 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:

o an increase in earnings of $5.7 million in 2006--related to two

separate contract settlements from our 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 our Colton, California processing facility. Secondly, we

recorded an expense of $0.5 million related to payments we made to

Motiva Enterprises LLC in June 2006 to settle claims for prior period

transmix purchase costs at our Richmond, Virginia processing facility.

We included the net income of $5.7 million from these two items within

"Other, net" in our accompanying consolidated statement of income for

the year ended December 31, 2006;

o a decrease in earnings of $105.0 million in 2005--due to an increase

in operating expenses related to an adjustment to our products

pipelines rate case liability in December 2005. This adjustment is

more fully described above in "Critical Accounting Policies and

Estimates--Legal Matters;"

o a decrease 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 as more fully described above in "Critical Accounting

Policies and Estimates--Environmental Matters;" and

o 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 our North System's natural gas

liquids inventory that was completed in the fourth quarter of 2005.

<PAGE>

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:

o 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 our

Products Pipelines segment (including Plantation Pipe Line Company,

our 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 income) 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;

o increases of $4.9 million (15%) and $18.6 million (133%),

respectively, from our Southeast refined products terminal operations.

Our Southeast terminal operations consist of 24 refined products

terminals located in the southeastern United States that we 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 we acquired in

March 2004 from ExxonMobil Corporation and the nine refined products

terminal operations we 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 we 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 we

owned all assets in both years) was primarily due to higher product

throughput revenues;

o increases of $4.1 million (1%) and $20.8 million (7%), respectively,

from our 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 our 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 our Pacific operations' North Line

<PAGE>

pipeline, largely due to our 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;

o increases of $3.7 million (12%) and $1.2 million (4%), respectively,

from our 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;

o an increase of $3.1 million (11%) and a decrease of $1.7 million (6%)

respectively, from the combined operations of our 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

our North System and a $0.2 million (4%) decrease from our Cypress

Pipeline. The increase from our 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 our North System and a $0.9 million (15%)

decrease from our 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.

o an increase of $2.6 million (13%) and a decrease of $2.0 million (9%),

respectively, from our petroleum pipeline transmix processing

operations. The 2006 increase consisted of incremental earnings of

$3.0 million from the inclusion of our Greensboro, North Carolina

transmix facility in 2006, and a decrease in earnings of $0.4 million

from the combined operations of our remaining transmix facilities,

largely due to higher operating, fuel and power costs which offset

increases in processing revenues. In the second quarter of 2006, we

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;

o an increase of $1.6 million (8%) and a decrease of $3.4 million (15%),

respectively, from our 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;

o decreases of $2.0 million (5%) and $2.6 million (6%), respectively,

from our 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

<PAGE>

above. These environmental expenses followed quarterly reviews of any

potential environmental issues that could impact our 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 our

Carson, California and our connected Los Angeles Harbor products

terminal.

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 our Gaffey Street products terminal located in

San Pedro, California; and

o a decrease of $0.2 million (0%) and an increase of $1.9 million (6%),

respectively, from our approximate 51% ownership interest in

Plantation Pipe Line Company. Earnings before depreciation, depletion

and amortization from our 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 our long-term note receivable from Plantation. In July

2004, we 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, we 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:

o increases of $24.5 million (43%) and $33.1 million (141%),

respectively, from our 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 we acquired in November 2004,

and $2.6 million attributable to the ExxonMobil terminals we acquired

in March 2004;

o increases of $16.2 million (5%) and $26.6 million (8%), respectively,

from our 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 our 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 we began offering in May

2005.

Our 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

<PAGE>

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 our completed North Line expansion with the

California Public Utility Commission. In November 2004, we filed an

application with the CPUC requesting a $9 million increase in existing

California intrastate transportation rates to reflect the in-service

date of our $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;

o an increase of $6.5 million (11%) in 2006 versus 2005 from our 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 our Carson/Los Angeles Harbor system

terminals;

o increases of $6.4 million (11%) and $5.0 million (9%), respectively,

from our 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 our 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;

o increases of $3.8 million (10%) and $2.8 million (8%), respectively,

from our 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;

o increases of $2.5 million (6%) and $1.4 million (3%), respectively,

from our 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

o decreases of $0.5 million (1%) and $1.8 million (5%), respectively,

from our 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, our 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, our CALNEV Pipeline delivery volumes were up

4.2% in 2006 versus 2005, due primarily to strong demand from the Southern

California and Las Vegas, Nevada markets. The overall decrease in year-to-year

segment deliveries of refined products was largely related to a 6.8% drop in

volumes from

<PAGE>

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 our 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

our Pacific operations' pipeline rate case liability in 2005; and (iv) the

expensing of inventory costs associated with the reconciliation of our 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:

o increases of $19.6 million (82%) and $14.5 million (153%),

respectively, from our 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 we acquired in

2004--including expenses of $13.0 million attributable to the Charter

terminals we acquired in November 2004, and $0.9 million attributable

to the ExxonMobil terminals we acquired in March 2004;

o increases of $18.3 million (18%) and $11.7 million (13%),

respectively, from our 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;

o increases of $9.0 million (46%) and $1.6 million (9%), respectively,

from our 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;

o increases of $0.2 million (2%) and $1.4 million (18%), respectively,

from our Central Florida Pipeline operations. The increase in 2006

compared to 2005 was due to incremental environmental expenses (not

<PAGE>

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;

o a decrease of $1.7 million (10%) and an increase of $2.9 million

(22%), respectively, from our 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, we acquired

an additional undivided 5% interest in the Cochin pipeline system for

approximately $10.9 million, bringing our total interest to 49.8%; and

o a decrease of $0.5 million (3%) and an increase of $2.9 million (16%),

respectively, from our 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 our Products Pipelines' 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 our approximate 51% interest in the pre-tax

income of Plantation Pipe Line Company and our 50% interest in the net income of

Heartland Pipeline Company and Johnston County Terminal, LLC. We include our

proportionate share of Plantation's income tax expenses within "Income taxes" in

our accompanying statements of income, and the interest income we earn on loans

to Plantation are reported within "Interest, net" in our accompanying statements

of income.

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 our 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 our 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.

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 our investment in

Plantation and a $0.8 million (55%) increase related to our investment in

Heartland. For our 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 our 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 our West Coast

terminals from reimbursable projects. For 2005, the increase primarily related

to incremental interest income of $2.5 million on our 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 our Pacific and Southeast

terminal operations. The increase from our Pacific operations related to higher

depreciable costs as a result of capital spending for both pipeline and storage

expansion since the end of 2005

<PAGE>

in order to strengthen and enhance our business operations on the West Coast.

The increase from our 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 we 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 our

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 we acquired in March and November 2004.

Natural Gas Pipelines

<TABLE>

Year Ended December 31,

--------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands, except operating statistics)

Revenues............................................................. $ 6,577,661 $ 7,718,384 $ 6,252,921

Operating expenses (including environmental adjustments)(a).......... (6,042,639) (7,254,979) (5,854,557)

Earnings from equity investments..................................... 40,447 36,812 19,960

Interest income and Other, net - income (expense).................... 753 2,729 1,832

Income taxes......................................................... (1,423) (2,622) (1,895)

------------- ------------ ------------

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity investments..... 574,799 500,324 418,261

Depreciation, depletion and amortization expense..................... (65,374) (61,661) (53,112)

Amortization of excess cost of equity investments.................... (285) (277) (277)

------------- ------------ ------------

Segment earnings................................................... $ 509,140 $ 438,386 $ 364,872

============= ============ =============

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

============= ============ =============

</TABLE>

----------------

(a) 2006 amount includes expense of $1,500 associated with supplemental

environmental liability adjustments, a $6,244 reduction in expense due to

the release of a reserve related to a natural gas pipeline contract

obligation, and a $15,114 gain from the combined sale of our Douglas

natural gas gathering system and Painter Unit fractionation facility. 2005

and 2004 amounts include decreases in expense of $89 and $7,602,

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).

Our Natural Gas Pipelines 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:

o an increase in earnings of $15.1 million in 2006--due to the sale of

our Douglas natural gas gathering system and Painter Unit

fractionation facility in April 2006. Effective April 1, 2006, we 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 income

for 2006. For more information on this gain, see Note 2 to our

consolidated financial statements included elsewhere in this report;

<PAGE>

o 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 our West Clear Lake natural gas storage

facility located in Harris County, Texas. We acquired this storage

facility as part of our acquisition of Kinder Morgan Tejas on January

31, 2002, and upon acquisition, we established a reserve for a

contract liability; and

o 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 our 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. Our 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 our 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 our Texas intrastate

group, and to incremental contributions from the inclusion of our 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. We acquired the TransColorado Pipeline from KMI 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 we 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:

o increases of $34.6 million (13%) and $30.1 million (13%),

respectively, from our 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 our

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, our 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 or 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 our natural gas purchase

and sales activities, thereby generating more stable earnings during

periods of fluctuating natural gas prices;

o increases of $10.2 million (10%) and $2.4 million (2%), respectively,

from our 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

<PAGE>

increase in revenues in 2005 versus 2004 was partially offset by lower

margins on operational gas sales and reduced cushion gas volumes sold;

o increases of $4.3 million (13%) and $17.3 million (119%),

respectively, from our 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, we 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;

o increases of $3.8 million (10%) and $33.5 million respectively, from

our 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);

o an increase of $2.3 million (21%) and a decrease of $5.1 million

(32%), respectively, from the combined operations of our 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 our Casper

Douglas natural gas gathering and processing operations. We benefited

from comparative differences in hedge settlements associated with the

rolling-off of older low price crude oil and propane positions at

December 31, 2005. 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;

o increases of $0.3 million (1%) and $10.9 million (28%), respectively,

from our 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, our 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

o a decrease of $0.8 million (13%) and an increase of $0.5 million (9%),

respectively, from the combined earnings of our remaining natural gas

operations, including our previous 50% investment in Coyote Gas

Treating, LLC and our 25% investment in Thunder Creek Gas Services,

LLC--the decrease in 2006 was due to both the absence of equity

earnings from our investment in Coyote and to lower natural gas

gathering income from Thunder Creek. Effective September 1, 2006, we

and the Southern Ute Indian Tribe contributed the value of our

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 our long-term note receivable from

Coyote. In 2005, we allocated this interest income to our Natural Gas

Pipelines business segment, versus treating it as unallocated interest

income in 2004. In March 2006, we contributed the principal amount of

$17.0 million related to this note to our equity investment in Coyote.

For more information on this note and on our equity contribution to

Red Cedar, see Note 12 to our consolidated financial statements

included elsewhere in this report.

<PAGE>

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 our Texas intrastate group's natural gas sales revenues and natural

gas purchase expenses, due primarily to year-over-year changes in natural gas

prices.

Our Intrastate group's purchase and sale activities result in considerably

higher revenues and operating expenses compared to the interstate operations of

our Rocky Mountain pipelines, which include our 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. We did, however, realize incremental revenues of $36.2 million and

incremental operating expenses of $4.5 million from the ownership of our

TransColorado Pipeline in the first ten months of 2005.

As discussed above, our 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 our 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 our 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.

Our 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.

We account 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 our 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 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 our 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 our 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 our Mier-Monterrey Mexico

Pipeline.

<PAGE>

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 our 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 our 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 our

Texas intrastate natural gas pipeline group, due to additional capital

investments made since the end of 2004.

CO2

<TABLE>

Year Ended December 31,

--------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands, except operating statistics)

Revenues(a).......................................................... $ 736,524 $ 657,594 $ 492,834

Operating expenses (including environmental adjustments)(b).......... (268,111) (212,636) (169,256)

Earnings from equity investments..................................... 19,173 26,319 34,179

Other, net - income (expense)........................................ 808 (5) 26

Income taxes......................................................... (224) (385) (147)

----------- ----------- -----------

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity investments..... 488,170 470,887 357,636

Depreciation, depletion and amortization expense(c).................. (190,922) (149,890) (121,361)

Amortization of excess cost of equity investments.................... (2,017) (2,017) (2,017)

----------- ----------- -----------

Segment earnings................................................... $ 295,231 $ 318,980 $ 234,258

=========== =========== ===========

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 Bbl(g)(h)...................... $ 31.42 $ 27.36 $ 25.72

=========== =========== ===========

Realized weighted average natural gas liquids price per

Bbl(h)(i).............................................................. $ 43.90 $ 38.98 $ 31.33

=========== =========== ===========

</TABLE>

-------------

(a) 2006 amount includes a $1,819 loss on derivative contracts used to hedge

forecasted crude oil sales.

(b) Includes expense of $298 in 2005 and a decrease in expense of $4,126 in

2004 associated with environmental liability adjustments.

oil and gas producing and gas processing activities in the amount of

$171,332 for 2006, $132,286 for 2005, and $105,890 for 2004. Includes

depreciation, depletion and amortization expense associated with sales and

transportation services activities in the amount of $19,590 for 2006,

$17,604 for 2005, and $15,471 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.

(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.

Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its

consolidated affiliates. The segment's primary businesses involve the

production, marketing and transportation of both carbon dioxide (commonly called

CO2) and crude oil, and the production and marketing of natural gas and natural

gas liquids. In 2006, our 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.

<PAGE>

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:

o an 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

o 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 as more fully described above in "Critical

Accounting Policies and Estimates--Environmental Matters."

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. We operate and own 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 our Central Basin Pipeline, our majority-owned Canyon Reef Carriers and Pecos

Pipelines, our Centerline Pipeline, and our 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 we hold ownership interests--these interests include our approximate 97%

working interest in the SACROC unit, located in Scurry County, Texas, and our

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

Texas.

In 2005, we 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, we 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 us to better manage crude oil deliveries

from our oil field interests in West Texas. During the first eight months of

2005, the Kinder Morgan Wink Pipeline accounted for

<PAGE>

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, our CO2 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, we made significant capital investments to increase

the capacity and deliverability of carbon dioxide and crude oil in and around

the Permian Basin. Our 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 our CO2

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 a

previously disclosed 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 our ownership interests in the net quantities of proved oil

and gas reserves and our measures of discounted future net cash flows from oil

and gas reserves, please see Note 20 to our consolidated financial statements

included elsewhere in this report.

As a result of our carbon dioxide and oil reserve ownership interests, we

are exposed to commodity price risk associated with physical crude oil and

natural gas liquids sales; however we mitigate this price risk 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. Our

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 our 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 our production costs and our selling price, in

an attempt to protect ourselves against the risk of adverse price changes and to

maintain a more stable and predictable earnings stream.

<PAGE>

Had we not used energy derivative contracts to transfer commodity price

risk, our crude oil 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 our unitholders from unpredictable

adverse events. All of our hedge gains and losses for crude oil and natural gas

liquids are included in our realized average price for oil; none are allocated

to natural gas liquids. For more information on our hedging activities, see Note

14 to our consolidated financial statements included elsewhere in this report.

Segment Details

Including the $1.8 million hedge ineffectiveness loss in 2006, our CO2

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:

o 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 our realized weighted average price of crude

oil and, in 2005, to a 16% increase in year-over-year sales volumes.

Our 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;

o 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;

o 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;

o 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 our realized weighted average natural gas liquids

price per barrel. In 2005, we also benefited from a 22% increase in

liquids processing volumes, as compared to 2004, primarily due to the

capital expenditures and infrastructure improvements we 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

o 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 we 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. We constructed the

SACROC power plant in order to reduce our purchases of electricity

from third-parties, but it reduces our 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.

KMI operates and maintains the power plant under a five-year contract

expiring in June 2010, and we pay KMI an annual operating and

maintenance fee.

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:

o 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

<PAGE>

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.

Our 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. We continue to

aggressively pursue opportunities to drill new wells and/or expand

existing wells for both carbon dioxide and crude oil in order to

benefit from robust demand for energy commodities in and around the

Permian Basin area. As discussed in Note 2 to our consolidated

financial statements included elsewhere in this report, in some cases,

the cost of carbon dioxide that is associated with enhanced oil

recovery is capitalized as part of our development costs when it is

injected. The carbon dioxide costs incurred and capitalized as

development costs for our CO2 segment were $100.5 million, $74.7

million and $70.6 million for the years ended December 31, 2006, 2005

and 2004, respectively;

o 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 we constructed at the SACROC oil field unit;

o 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

o 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 as

more fully described above in "Critical Accounting Policies and

Estimates--Environmental Matters."

Earnings from equity investments, representing equity earnings from our 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 we 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, we also realized incremental depreciation charges of $3.4

million attributable to the various oil and gas properties we 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. Our 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.

<PAGE>

Terminals

<TABLE>

Year Ended December 31,

--------------------------------------------

2006 2005 2004

---------- ---------- ----------

(In thousands, except operating statistics)

Revenues............................................................. $ 864,844 $ 699,264 $ 541,857

Operating expenses (including environmental adjustments)(a).......... (446,817) (373,410) (254,115)

Earnings from equity investments..................................... 214 83 1

Other, net - income (expense)........................................ 2,118 (220) (396)

Income taxes(b)...................................................... (12,226) (11,111) (5,609)

----------- ----------- -----------

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity investments..... 408,133 314,606 281,738

Depreciation, depletion and amortization expense..................... (74,541) (59,077) (42,890)

Amortization of excess cost of equity investments.................... - - -

----------- ----------- -----------

Segment earnings................................................... $ 333,592 $ 255,529 $ 238,848

=========== =========== ===========

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%

=========== =========== ===========

</TABLE>

------------------

(a) 2006 amount includes an increase in expense of $2,792 related to hurricane

clean-up and repair activities, and a gain of $15,192 from property

casualty indemnifications. Also, includes an increase in expense of $3,535

in 2005 and a decrease in expense of $18,651 in 2004 associated with

environmental liability adjustments.

(b) 2006 amount includes expense of $1,125 associated with hurricane expenses

and casualty gain. 2004 amount includes expense of $80 associated with

environmental liability adjustments.

Our Terminals segment includes the operations of our petroleum and

petrochemical-related liquids terminal facilities (other than those included in

our Products Pipelines segment), and all of our 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:

o 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 we operate

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 our International Marine Terminals

facility, a Louisiana partnership owned 66 2/3% by us. IMT is a

multi-purpose bulk commodity transfer terminal facility located in

Port Sulphur, Louisiana.

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 and

<PAGE>

described below in "--Other," total hurricane income and expense

items increased our net income by $8.6 million in 2006. For more

information on our property casualty gain, see Note 6 to our

consolidated financial statements included elsewhere in this report;

and

o 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 as more fully described above in "Critical

Accounting Policies and Estimates--Environmental Matters."

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. We

make and continue to seek key terminal acquisitions in order to gain access to

new markets, to complement and/or enlarge our existing terminal operations, and

to benefit from the economies of scale resulting from increases in storage,

handling and throughput capacity.

Segment Earnings before Depreciation, Depletion and Amortization

Terminal Acquisitions

Our significant terminal acquisitions since the beginning of 2005 included

the following:

o our Texas Petcoke terminals, located in and around the Ports of

Houston and Beaumont, Texas, acquired effective April 29, 2005;

o three terminals acquired separately in July 2005: our Kinder Morgan

Staten Island terminal, a dry-bulk terminal located in Hawesville,

Kentucky and a liquids/dry-bulk facility located in Blytheville,

Arkansas;

o 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;

o our Kinder Morgan Blackhawk terminal located in Black Hawk County,

Iowa, acquired in August 2005;

o a terminal-related repair shop located in Jefferson County, Texas,

acquired in September 2005;

o 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

o 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.

We have 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 our Texas petroleum coke terminals and repair shop assets,

which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an

aggregate consideration of approximately $247.2 million. The primary assets

acquired included facilities and railway equipment located at the Port of

Houston, the Port of Beaumont and the TGS Deepwater terminal located on the

Houston Ship Channel. 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, we benefited significantly from the incremental contributions

attributable to the bulk and liquids terminal businesses we acquired since the

end of the third quarter of 2004. In addition to the 2005 acquisitions referred

to above, these acquisitions included:

<PAGE>

o 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

o our Kinder Morgan Fairless Hills terminal located along the Delaware

River in Bucks County, Pennsylvania, acquired effective December 1,

2004.

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 we owned the assets in

2005 and 2004, respectively. For more information in regard to our terminal

acquisitions, see Note 3 to our consolidated financial statements included

elsewhere in this report.

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:

o increases of $17.4 million (23%) and $13.7 million (22%),

respectively, from our Gulf Coast region. This region includes the

operations of our 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 our 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, we have obtained additional customer contracts,

extended existing customer contracts and remarketed expiring

contracted capacity at competitive rates. For our Gulf Coast and other

liquids terminals, our existing contracts generally mature at various

times and in varying amounts of throughput capacity, therefore, we

continue to manage our recontracting process in order to limit the

risk of significant impacts on our 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;

o an increase of $9.4 million (29%) and a decrease of $3.3 million

(10%), respectively, from our Mid-Atlantic region. The 2006 increase

was driven by a $5.7 million increase from our Shipyard River

terminal, located in Charleston, South Carolina; a $2.6 million

increase from our Fairless Hills, Pennsylvania bulk terminal; and a

$1.2 million increase from our 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).

<PAGE>

The decrease in earnings in 2005 compared to 2004 included a $2.1

million decrease in earnings from our Pier IX bulk terminal, located

in Newport News, Virginia, and a $2.0 million decrease in earnings

from our 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 our Chesapeake terminal was mainly due to higher

operating expenses associated with higher movements of petroleum coke;

o an increase of $4.6 million (19%) and a decrease of $0.8 million,

respectively, from terminals included in our 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 our Texas Petcoke region,

which was newly formed in April 2005;

o an increase of $4.5 million (16%) and a decrease of $7.2 million

(21%), respectively, from terminals included in our Lower Mississippi

River (Louisiana) region. The increase in 2006 compared to 2005 was

primarily due to incremental earnings from our Amory and DeLisle

Mississippi bulk terminals, and from higher earnings from our Kinder

Morgan St. Gabriel, Louisiana terminal. Our Amory terminal began

operations in July 2005. The higher earnings from our DeLisle

terminal, which was negatively impacted by hurricane damage in 2005,

was primarily due to higher bulk transfer revenues in 2006. The

increase from our 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 our 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, our Terminals segment

realized essentially all of our 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. We also

recognized another $0.8 million to repair damaged facilities following

Hurricane Rita, but estimates of lost business at our terminal sites

are difficult because of insurance complexities and the extended

recovery time involved;

o an increase of $3.7 million (8%) and a decrease of $1.0 million (2%),

respectively, from terminals included in our Northeast region. The

increase in 2006 compared to 2005 was primarily due to higher earnings

from our 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 our 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 our Staten Island terminal.

The decrease in 2005 compared to 2004 was driven by lower earnings

from the dry-bulk services at our 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

o increases of $2.2 million (4%) and $4.4 million (10%), respectively,

from terminals in our Midwest region. The year-over-year increase in

earnings in 2006 was mainly attributable to higher earnings from the

combined operations of our Argo and Chicago, Illinois liquids

terminals, and from our 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 our Dakota bulk terminal, located along the Mississippi River

near St. Paul, Minnesota; our Argo, Illinois liquids terminal,

situated along the Chicago sanitary and ship channel; and our

Milwaukee, Wisconsin bulk commodity terminal. The increase in earnings

from Dakota was primarily due to higher revenues generated by a cement

unloading and

<PAGE>

storage facility, which began operations in late 2004. The increase

from our Argo terminal was mainly due to new customer contracts and

higher ethanol handling revenues. The increase from our 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:

o a $24.1 million (29%) increase from our 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 our North

Charleston terminals, all discussed above. Also, our 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%;

o a $19.6 million (19%) increase from our Gulf Coast liquids facilities,

due primarily to higher revenues from Pasadena and Galena Park, as

discussed above;

o a $19.1 million (43%) increase from our Texas Petcoke terminal region,

due primarily to higher petroleum coke transfer volumes;

o 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;

o a $5.5 million (5%) increase from terminals included in our Midwest

region, due largely to the increased liquids throughput, storage and

ethanol activities from our two Chicago liquids terminals and to the

increased coal volumes from our Cora coal terminal, both described

above. The overall increase in revenues was also due to higher marine

oil fuel and asphalt sales from our Dravosburg, Pennsylvania bulk

terminal;

o a $5.1 million (16%) increase from our Ferro alloys region, largely

due to increased ores and metals handling at our Chicago and Industry,

Pennsylvania terminals; and

o a $4.6 million (5%) increase from our Northeast terminals, largely due

to the revenue increases at our 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. We also

completed, in 2006, capital expansion and betterment projects at certain of

our liquids terminal facilities that included the construction of additional

petroleum products storage tanks. The construction, when combined with

increases from external acquisitions, increased our liquids storage capacity

by approximately 1.1 million barrels (2.6%) in 2006. At the same time, we

increased our liquids utilization capacity rate by 1%, compared to the prior

year. Our liquids terminals utilization rate is the ratio of our actual

leased capacity to our estimated potential capacity. Potential capacity is

generally derived from measures of total capacity, taking into account

periodic changes to our 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:

o a $16.7 million (19%) increase from our Pasadena and Galena Park Gulf

Coast liquids terminals, due primarily to higher petroleum transmix

sales and to additional customer contracts and tankage capacity;

<PAGE>

o a $12.3 million (14%) increase from our Midwest region, due primarily

to higher cement handling revenues at our Dakota terminal, increased

tonnage at our Milwaukee terminal, and higher marine fuel sales at our

Dravosburg, Pennsylvania terminal;

o a $6.8 million (11%) increase from our Mid-Atlantic region, due

primarily to higher coal volumes and higher dockage revenues at our

Shipyard River terminal, higher cement, iron ore, and dockage revenues

at our Pier IX bulk terminal, and incremental revenues from our North

Charleston liquids/bulk terminal, located just north of our Shipyard

facility and acquired effective April 30, 2004;

o a $4.0 million (38%) increase from our engineering and terminal design

services, due to increased fee revenues discussed above;

o a $3.9 million (9%) increase from our Southeast region, due primarily

to both higher fertilizer and ammonia volumes and higher stevedoring

services at our terminal operations located in and around the Tampa,

Florida area. These operations include the import and export business

of our Kinder Morgan Tampaplex terminal, the commodity transfer

operations of our Port Sutton terminal, and the terminal stevedoring

services we perform along Tampa Bay; and

o a $2.8 million (3%) decrease from terminals included in our Louisiana

region. The decrease was largely due to the negative impact and

business interruptions resulting from the two hurricanes that struck

the Gulf Coast in the second half of 2005.

Operating expenses from all terminals owned during identical periods of

both 2006 and 2005 increased $38.1 million (10%) in 2006 compared to 2005.

Combined, the net effect of the environmental liability adjustments,

hurricane repair expenses, and the property casualty gain on terminals owned

during the same portions of both comparable periods resulted in a $15.9

million decrease in segment operating expenses in 2006 relative to 2005. The

remaining change in year-to-year operating expenses--an increase of $54.0

million (15%)--from all terminals owned during identical periods of both 2006

and 2005 primarily consisted of the following:

o a $15.3 million (111%) increase from engineering-related services, due

primarily to higher salary, overtime and other employee-related

expenses related to new hiring, as well as increased contract labor,

all associated with the increased project work described above;

o a $15.0 million (75%) increase from our Texas Petcoke terminal region,

due largely to higher labor expenses, rail service and railcar

maintenance expenses, and harbor and barge expenses, all related to

higher petroleum coke volumes;

o a $14.1 million (28%) increase from our Mid-Atlantic terminals,

largely due to higher operating and maintenance expenses at our

Fairless Hills, Shipyard River, and Philadelphia terminals. The

increase at Fairless Hills was largely due to higher wharfage,

trucking and general maintenance expenses, related to the increase in

steel products handled. The increase at Shipyard was due to higher

labor, equipment rentals and general maintenance expenses, all

associated with increased tonnage. The increase at our Philadelphia

liquids terminal was due to higher expenses related to certain

environmental liability accruals;

o a $4.0 million (21%) increase from terminals in our Ferro alloys

region, due primarily to higher labor expenses and higher equipment

maintenance and rental expenses, all related to increased ores and

metals handling volumes; and

o a $3.7 million (6%) increase from our Midwest region terminals, due

primarily to higher marine fuel costs of sales expenses at our

Dravosburg terminal; higher maintenance and outside service expenses

associated with increases in coal transfer volumes at our Cora,

Illinois and Grand Rivers, Kentucky coal terminals; and additional

labor and equipment rental expenses from the combined operations of

our Argo and Chicago, Illinois liquids terminals, due to increased

ethanol throughput and incremental liquids storage and handling

business.

<PAGE>

For terminal operations owned during the same months of both 2005 and 2004,

operating expenses increased $54.3 million (21%) in 2005 compared to 2004.

The overall increase included a $22.1 million increase in expense

attributable to the 2005 and 2004 environmental liability adjustments. The

remaining $32.2 million (12%) increase in operating expenses in 2005 versus

2004 from terminal operations owned during both years primarily consisted of

the following:

o a $10.1 million (36%) increase from our Mid-Atlantic terminals,

largely due to higher operating, maintenance and labor expenses at our

Pier IX and Chesapeake Bay facilities, discussed above, and to higher

operating, equipment maintenance and labor expenses at our Shipyard

River terminal, due to higher bulk tonnage volumes;

o an $8.5 million (18%) increase from our Midwest region terminals, due

primarily to higher expenses at our Milwaukee, Dravosburg and Dakota

bulk handling terminals. The increase at our Milwaukee bulk commodity

terminal was due to increased trucking and maintenance expenses

associated with the increase in coal volumes. The increase at

Dravosburg was largely due to higher cost of sales expenses, due to

marine oil purchasing costs and inventory maintenance, and the

increase at our St. Paul, Minnesota Dakota bulk terminal was due to

both higher repair and labor expenses, associated with higher cement

volumes, and lower capitalized overhead in 2005, due to the completion

of its cement unloading and storage facility in late 2004;

o a $3.1 million (5%) increase from our Louisiana terminals, largely due

to property damage, demurrage and other expenses, which in large part

related to the effects of hurricanes Katrina and Rita in the last half

of 2005. However, since the affected properties were insured, our

expenses were limited to the amount of the deductible under our

insurance policies;

o a $2.9 million (12%) increase from our Pasadena and Galena Park Gulf

Coast liquids terminals, due chiefly to higher labor, and higher fuel

and power expenses associated with increased terminal activities; and

o a $2.6 million (21%) increase from the terminals in our West region,

due mainly to higher labor expenses and port fees resulting from

increased tonnage at our terminal facilities located at Longview and

Vancouver, Washington. Both facilities provide ship loading services

along the Columbia River.

The segment's earnings from equity investments remained flat across both

2006 and 2005, when compared to prior years. Income from other items was

essentially unchanged in 2005 versus 2004, but increased $2.3 million in 2006

compared to 2005. The increase in 2006 was chiefly due to the $1.8 million

income item related to a settlement associated with our Kinder Morgan St.

Gabriel terminal, discussed above, and to a $1.2 million increase related to a

disposal loss, recognized in 2005, on warehouse property at our Elizabeth River

bulk terminal, located in Chesapeake, Virginia.

Income tax expenses totaled $12.2 million in 2006, $11.1 million in 2005

and $5.6 million in 2004. The $1.1 million (10%) increase in 2006 versus 2005

reflects, among other things, incremental income tax expense associated with

hurricane related income and expense items. The $5.5 million (98%) increase in

2005 compared to 2004 was mainly attributable to the year-to-year changes in

both taxable income and certain permanent differences between taxable income and

financial income of Kinder Morgan Bulk Terminals, Inc. and its consolidated

subsidiaries. Kinder Morgan Bulk Terminals, Inc. is the tax-paying entity that

owns many of our bulk terminal businesses which handle non-qualifying products.

In general, the segment's income tax expenses will change period to period based

on the classification of income before taxes between amounts earned by corporate

subsidiaries and amounts earned by partnership subsidiaries.

Non-cash depreciation, depletion and amortization charges increased $15.5

million (26%) in 2006 compared to 2005 and $16.2 million (38%) in 2005 compared

to 2004. The year-over-year increases in depreciation expenses reflect a rising

depreciable capital base since the end of 2004, with growth due to a combination

of business acquisitions and internal capital spending. Collectively, the

terminal assets we acquired since the beginning of 2005 and listed above

accounted for incremental depreciation expenses of $8.2 million in 2006, and the

assets we acquired since the third quarter of 2004 and listed above accounted

for incremental depreciation expenses of $12.4 million in 2005. The remaining

increases in year-to-year depreciation expenses were associated with capital

<PAGE>

spending on numerous improvement projects completed since 2004 in order to

expand and enhance our terminal services.

Other

<TABLE>

Year Ended December 31,

2006 2005 2004

----------- ----------- ------------

(In thousands - income/(expense))

General and administrative expenses(a)................. $ (219,575) $ (216,706) $ (170,507)

Unallocable interest, net.............................. (336,130) (264,203) (194,973)

Minority interest(b)................................... (15,015) (7,262) (9,679)

Loss from early extinguishment of debt................. - - (1,562)

----------- ----------- ------------

Interest and corporate administrative expenses....... $ (570,720) $ (488,171) $ (376,721)

</TABLE>

__________

(a) 2006 amount includes a decrease in expense of $393 related to the

allocation of general and administrative expenses on hurricane related

capital expenditures for the replacement and repair of assets.

(b) 2006 amount includes an expense of $3,075 related to the allocation of

International Marine Terminals' earnings from hurricane income and expense

items to minority interest.

Items not attributable to any segment include general and administrative

expenses, unallocable interest income, interest expense and minority interest.

We also included the $1.6 million loss from our early extinguishment of debt in

2004 as an item not attributable to any business segment. The loss from the

early extinguishment of debt represented the excess of the price we paid to

repurchase and retire the principal amount of $87.9 million of tax-exempt

industrial revenue bonds over the bonds' carrying value. Pursuant to certain

provisions that gave us the right to call and retire the bonds prior to

maturity, we took advantage of the opportunity to refinance at lower rates, and

we included the $1.6 million loss under the caption "Other, net" in our

accompanying consolidated statement of income. For more information on this

early extinguishment of debt, see Note 9 to our consolidated financial

statements, included elsewhere in this report.

Our general and administrative expenses include such items as salaries and

employee-related expenses, payroll taxes, insurance, office supplies and

rentals, unallocated litigation and environmental expenses, and shared corporate

services--including accounting, information technology, human resources and

legal services. Overall general and administrative expenses totaled $219.6

million in 2006, $216.7 million in 2005 and $170.5 million in 2004. Generally,

the year-to-year increases in our general and administrative expenses reflect

increased spending levels in support of our growth initiatives, and we continue

to aggressively manage our infrastructure expense and to focus on our

productivity and expense controls.

The $2.9 million (1%) increase in overall general and administrative

expenses in 2006 compared to 2005 was primarily due to higher corporate service

charges and higher corporate and employee-related insurance expenses in 2006,

when compared to the prior year. The increase in corporate services was largely

due to higher corporate overhead expenses associated with the business

operations we acquired since the end of 2005. The increase in insurance expenses

was partly due to incremental expenses related to the cancellation of certain

commercial insurance polices in the second quarter of 2006, as well as to the

overall variability in year-to-year commercial property and medical insurance

costs. Pursuant to certain provisions that gave us the right to cancel certain

commercial policies prior to maturity, we took advantage of the opportunity to

reinsure at lower rates.

The overall increase in general and administrative expenses in 2006

compared to 2005 was partly offset a $33.4 million decrease in unallocated

litigation and environmental settlement expenses and a $0.4 million decrease in

expense from the allocation of general and administrative overhead expenses to

hurricane related capital projects. The decrease in expense from unallocated

litigation and environmental settlement expenses consisted of: (i) a $25.0

million expense in 2005 for a settlement reached between us and a former joint

venture partner on our Kinder Morgan Tejas natural gas pipeline system; and (ii)

a cumulative $8.4 million expense in 2005 related to settlements of

environmental matters at certain of our operating sites located in the State of

California. For more information on our litigation matters, see Note 16 to our

consolidated financial statements, included elsewhere in this report.

The $46.2 million (27%) increase in general and administrative expenses in

2005 compared to 2004 was due to the incremental litigation and environmental

settlement expenses of $33.4 million described above, as well as higher

<PAGE>

expenses incurred from KMI's operation of our natural gas pipeline assets

(associated with higher actual costs in 2005 versus lower negotiated costs in

2004), higher insurance expenses (largely due to higher workers compensation

claims) and higher legal, benefits, and corporate secretary services expenses.

Interest expense, net of unallocable interest income, totaled $336.1

million in 2006, $264.2 million in 2005 and $195.0 million in 2004. The $71.9

million (27%) increase in net interest expense in 2006 compared to 2005 was due

to both higher average debt levels and higher effective interest rates. In 2006,

average borrowings (excluding the market value of interest rate swaps) increased

10% and the weighted average interest rate on all of our borrowings increased

17%, when compared to 2005 (the weighted average interest rate on all of our

borrowings was approximately 6.1779% during 2006 and 5.3019% during 2005). The

increase in average borrowings was mainly due to higher capital spending in

2006, the acquisition of external assets and businesses since the end of 2005,

and a net increase, since March 2005, of $300 million in principal amount of

long-term senior notes.

Generally, we fund both our capital spending (including payments for

pipeline project construction costs) and our acquisition outlays from borrowings

under our commercial paper program. The net changes in the principal amount of

our senior notes relate to changes occurring on March 15, 2005. On that date, we

both closed a public offering of $500 million in principal amount of senior

notes and retired a principal amount of $200 million. From time to time we issue

senior notes in order to refinance our commercial paper borrowings. For more

information on our capital expansion and acquisition expenditures, see

"Liquidity and Capital Resources - Investing Activities".

The increase in our average borrowing rate in 2006 reflects a general rise

in variable interest rates since the end of 2005. We use interest rate swap

agreements to help manage our interest rate risk. The swaps are contractual

agreements we enter into in order to transform a portion of the underlying cash

flows related to our long-term fixed rate debt securities into variable rate

debt in order to achieve our desired mix of fixed and variable rate debt.

However, in a period of rising interest rates, these swaps will result in

period-to-period increases in our interest expense. For more information on our

interest rate swaps, see Note 14 to our consolidated financial statements,

included elsewhere in this report.

The $69.2 million (35%) increase in net interest charges in 2005 versus

2004 was also due to both higher average debt borrowings and higher effective

interest rates. Our average debt balance increased 10% in 2005 compared to 2004,

partly due to incremental borrowings made in connection with both internal

capital spending and external acquisitions, and partly due to the net increase

of $300 million in principal amount of senior notes in March 2005. The weighted

average interest rate on all of our borrowings increased 19% in 2005 compared to

2004, reflecting a general rise in interest rates since the end of 2004.

Minority interest, representing the deduction in our consolidated net

income attributable to all outstanding ownership interests in our five operating

limited partnerships and their consolidated subsidiaries that are not held by

us, totaled $15.0 million in 2006, $7.3 million in 2005 and $9.7 million in

2004. The overall $7.7 million (105%) increase in 2006 compared to 2005 included

a $3.1 million increase attributable to the 33 1/3% minority interest in the IMT

Partnership's hurricane related income and expense items, as described above in

"--Terminals," and a $1.6 million increase attributable to higher net income

from overall net operating partnership income. The overall $2.4 million (25%)

decrease in minority interest in 2005 compared to 2004 was chiefly due to lower

net income allocated to the minority interest in the IMT Partnership in 2005,

due to business interruption caused by Hurricane Katrina.

Liquidity and Capital Resources

Capital Structure

We attempt to maintain a conservative overall capital structure, with a

long-term target mix of approximately 50% equity and 50% debt. In addition to

our results of operations, our debt and capital balances are affected by our

financing activities, as discussed below in "--Financing Activities." The

following table illustrates the sources of our invested capital (dollars in

thousands):

<PAGE>

<TABLE>

December 31,

-----------------------------------------

2006 2005 2004

------------ ------------ ------------

Long-term debt, excluding market value of interest rate swaps.... $ 4,384,332 $ 5,220,887 $ 4,722,410

Minority interest................................................ 50,599 42,331 45,646

Partners' capital, excluding accumulated other

comprehensive loss............................................. 4,863,207 4,693,414 4,353,863

------------ ------------ ------------

Total capitalization........................................... 9,298,138 9,956,632 9,121,919

Short-term debt, less cash and cash equivalents.................. 1,345,084 (12,108) -

------------ ------------ ------------

Total invested capital......................................... $ 10,643,222 $ 9,944,524 $ 9,121,919

============ ============ ============

Capitalization:

Long-term debt, excluding market value of interest rate swaps.. 47.2% 52.4% 51.8%

Minority interest.............................................. 0.5% 0.4% 0.5%

Partners' capital, excluding accumulated other comprehensive

loss......................................................... 52.3% 47.2% 47.7%

------------ ------------ ------------

100.0% 100.0% 100.0%

============ ============ ============

Invested Capital:

Total debt, less cash and cash equivalents and excluding market

value of interest rate swaps................................. 53.8% 52.4% 51.8%

Partners' capital and minority interest, excluding accumulated

other comprehensive loss .................................... 46.2% 47.6% 48.2%

------------ ------------ ------------

100.0% 100.0% 100.0%

============ ============ ============

</TABLE>

Our primary cash requirements, in addition to normal operating expenses,

are debt service, sustaining capital expenditures, expansion capital

expenditures and quarterly distributions to our common unitholders, Class B

unitholders and general partner. In addition to utilizing cash generated from

operations, we could meet our cash requirements for expansion capital

expenditures through borrowings under our credit facility, issuing short-term

commercial paper, long-term notes or additional common units or the proceeds

from purchases of additional i-units by KMR with the proceeds from issuances of

KMR shares.

In general, we expect to fund:

o cash distributions and sustaining capital expenditures with existing

cash and cash flows from operating activities;

o expansion capital expenditures and working capital deficits with

retained cash (resulting from including i-units in the determination

of cash distributions per unit but paying quarterly distributions on

i-units in additional i-units rather than cash), additional

borrowings, the issuance of additional common units or the proceeds

from purchases of additional i-units by KMR;

o interest payments with cash flows from operating activities; and

o debt principal payments with additional borrowings, as such debt

principal payments become due, or by the issuance of additional common

units or the proceeds from purchases of additional i-units to KMR.

As a publicly traded limited partnership, our common units are attractive

primarily to individual investors, although such investors represent a small

segment of the total equity capital market. We believe that some institutional

investors prefer shares of KMR over our common units due to tax and other

regulatory considerations. We are able to access this segment of the capital

market through KMR's purchases of i-units issued by us with the proceeds from

the sale of KMR shares to institutional investors.

As part of our financial strategy, we try to maintain an investment-grade

credit rating, which involves, among other things, the issuance of additional

limited partner units in connection with our acquisitions and internal growth

activities in order to maintain acceptable financial ratios. On May 30, 2006,

S&P and Moody's each placed our ratings on credit watch pending resolution of a

management buyout proposal for all of the outstanding shares of KMI. On January

5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to

BBB and removed our rating from credit watch with negative implications. Our

debt credit ratings are currently rated BBB by Standard & Poor's Rating

Services, and Baa1 by Moody's Investors Service. As noted by Moody's in its

credit opinion dated November 15, 2006, our rating is expected to be downgraded

from Baa1 to Baa2 at the time Moody's

<PAGE>

finalizes its ratings for KMI. Additionally, as noted by Fitch in its press

release dated August 28, 2006, our rating is expected to be downgraded from BBB+

to BBB at the time Fitch finalizes its ratings for KMI. At this time, neither

Moody's nor Fitch have changed their ratings on KMI or us. We are not able to

predict with certainty the final outcome of the pending buyout proposal.

Short-term Liquidity

We employ a centralized cash management program that essentially

concentrates the cash assets of our operating partnerships and their

subsidiaries in joint accounts for the purpose of providing financial

flexibility and lowering the cost of borrowing. Our centralized cash management

program provides that funds in excess of the daily needs of our operating

partnerships and their subsidiaries are concentrated, consolidated, or otherwise

made available for use by other entities within our consolidated group. We place

no restrictions on the ability to move cash between entities, payment of

inter-company balances or the ability to upstream dividends to parent companies

other than restrictions that may be contained in agreements governing the

indebtedness of those entities; provided, however, that our cash and the cash of

our subsidiaries is not concentrated into accounts of KMI or any company not in

our consolidated group of companies, and KMI has no rights with respect to our

cash except as permitted pursuant to our partnership agreement.

Furthermore, certain of our operating subsidiaries are subject to Federal

Energy Regulatory Commission enacted reporting requirements for oil and natural

gas pipeline companies that participate in cash management programs.

FERC-regulated entities subject to these rules must, among other things, place

their cash management agreements in writing, maintain current copies of the

documents authorizing and supporting their cash management agreements, and file

documentation establishing the cash management program with the FERC.

Our principal sources of short-term liquidity are:

o our $1.85 billion five-year senior unsecured revolving credit facility

that matures August 18, 2010;

o our $1.85 billion short-term commercial paper program (which is

supported by our bank credit facility, with the amount available for

borrowing under our credit facility being reduced by our outstanding

commercial paper borrowings); and

o cash from operations (discussed following).

Borrowings under our credit facility can be used for general corporate

purposes and as a backup for our commercial paper program. Effective August 28,

2006, we terminated our $250 million unsecured nine-month bank credit facility

due November 21, 2006, and we increased our existing five-year bank credit

facility from $1.60 billion to $1.85 billion. The five-year unsecured bank

credit facility remains due August 18, 2010; however, the bank facility can now

be amended to allow for borrowings up to $2.1 billion. There were no borrowings

under our bank credit facility as of December 31, 2005 or as of December 31,

2006. As of December 31, 2006, we had $1,098.2 million of commercial paper

outstanding.

We provide for additional liquidity by maintaining a sizable amount of

excess borrowing capacity related to our commercial paper program and long-term

revolving credit facility. After inclusion of our outstanding commercial paper

borrowings and letters of credit, the remaining available borrowing capacity

under our bank credit facility was $367.1 million as of December 31, 2006. As of

December 31, 2006, our outstanding short-term debt was $1,359.1 million.

Currently, we believe our liquidity to be adequate. For more information on our

commercial paper program and our credit facility, see Note 9 to our consolidated

financial statements included elsewhere in this report.

Long-term Financing

In addition to our principal sources of short-term liquidity listed above,

we could meet our cash requirements (other than distributions to our common

unitholders, Class B unitholders and general partner) through issuing long-term

notes or additional common units, or the proceeds from purchases of additional

i-units by KMR with the proceeds from issuances of KMR shares.

We are subject, however, to changes in the equity and debt markets for our

limited partner units and long-term notes, and there can be no assurance we will

be able or willing to access the public or private markets for our limited

partner units and/or long-term notes in the future. If we were unable or

unwilling to issue additional limited partner

<PAGE>

units, we would be required to either restrict potential future acquisitions or

pursue other debt financing alternatives, some of which could involve higher

costs or negatively affect our credit ratings. Our ability to access the public

and private debt markets is affected by our credit ratings. See "--Capital

Structure" above for a discussion of our credit ratings.

In August 2006, we issued, in a public offering, 5,750,000 of our 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. We received net proceeds of approximately $248.0 million for the

issuance of these 5,750,000 common units.

From time to time we issue long-term debt securities. All of our long-term

debt securities issued to date, other than those issued under our long-term

revolving credit facility or those issued by our subsidiaries and operating

partnerships, generally have the same terms except for interest rates, maturity

dates and prepayment premiums. All of our outstanding debt securities are

unsecured obligations that rank equally with all of our other senior debt

obligations; however, a modest amount of secured debt has been incurred by some

of our operating partnerships and subsidiaries. Our fixed rate notes provide

that we may redeem the notes at any time at a price equal to 100% of the

principal amount of the notes plus accrued interest to the redemption date plus

a make-whole premium.

As of December 31, 2006, our total liability balance due on the various

series of our senior notes was $4,490.7 million, and the total liability balance

due on the various borrowings of our operating partnerships and subsidiaries was

$154.5 million.

In addition, on January 30, 2007, we completed a public offering of senior

notes. We issued a total of $1.0 billion in principal amount of senior notes,

consisting of $600 million of 6.00% notes due February 1, 2017 and $400 million

of 6.50% notes due February 1, 2037. We received proceeds from the issuance of

the notes, after underwriting discounts and commissions, of approximately $992.8

million, and we used the proceeds to reduce the borrowings under our commercial

paper program. For additional information regarding our debt securities, see

Note 9 to our consolidated financial statements included elsewhere in this

report.

Capital Requirements for Recent Transactions

During 2006, our cash outlays for the acquisition of assets totaled $397.4

million. We utilized our commercial paper program to fund our 2006 acquisitions.

We then reduced our short-term borrowings with the proceeds from our August

issuance of common units. We intend to refinance the remainder of our current

short-term debt and any additional short-term debt incurred during 2007 through

a combination of long-term debt, equity and the issuance of additional

commercial paper to replace maturing commercial paper borrowings.

We are committed to maintaining a cost effective capital structure and we

intend to finance new acquisitions using a mix of approximately 50% equity

financing and 50% debt financing. For more information on our capital

requirements during 2006 in regard to our acquisition expenditures, see Note 3

to our consolidated financial statements included elsewhere in this report.

Off Balance Sheet Arrangements

We have invested in entities that are not consolidated in our financial

statements. As of December 31, 2006, our obligations with respect to these

investments, as well as our obligations with respect to a letter of credit, are

summarized below (dollars in millions):

<PAGE>

<TABLE>

Our

Our Remaining Total Total Contingent

Investment Ownership Interest(s) Entity Entity Share of

Entity Type Interest Ownership Assets(5) Debt Entity Debt(6)

------------------------------ ---------- --------- ------------ --------- ------ -------------

General

Cortez Pipeline Company........ Partner 50% (1) $73.7 $148.9 $74.5(2)

Red Cedar Gathering General Southern Ute

Company.................... Partner 49% Indian Tribe $247.5 $31.4 $15.4

ConocoPhillips

Limited and

West2East Pipeline LLC(3)...... Liability 51% Sempra Energy $850.5 $790.1 $403.0

Nassau County,

Nassau County, Florida Ocean

Florida Ocean Highway Highway and

and Port Authority (4)..... N/A N/A Port Authority N/A N/A $23.9

---------

</TABLE>

(1) The remaining general partner interests are owned by ExxonMobil Cortez

Pipeline, Inc., an indirect wholly-owned subsidiary of ExxonMobil

Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of

M.E. Zuckerman Energy Investors Incorporated.

(2) We are severally liable for our percentage ownership share (50%) of the

Cortez Pipeline Company debt. Shell Oil Company shares our several guaranty

obligations jointly and severally; however, we are obligated to indemnify

Shell for liabilities it incurs in connection with such guaranty.

Accordingly, in December 2006 and January 2007 we entered into two separate

letters of credit, each in the amount of $37.5 million issued by JP Morgan

Chase, in order to secure our indemnification obligations to Shell for 50%

of the Cortez debt balance of $148.9 million.

Further, pursuant to a Throughput and Deficiency Agreement, the partners of

Cortez Pipeline Company are required to contribute capital to Cortez in the

event of a cash deficiency. The agreement contractually supports the

financings of Cortez Capital Corporation, a wholly-owned subsidiary of

Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to

fund cash deficiencies at Cortez Pipeline, including anticipated

deficiencies and cash deficiencies relating to the repayment of principal

and interest on the debt of Cortez Capital Corporation. The partners'

respective parent or other companies further severally guarantee the

obligations of the Cortez Pipeline owners under this agreement.

(3) West2East Pipeline LLC is a limited liability company and is the sole owner

of Rockies Express Pipeline LLC. As of December 31, 2006, the remaining

limited liability member interests in West2East Pipeline LLC are owned by

ConocoPhillips (24%) and Sempra Energy (25%). We owned a 66 2/3% ownership

interest in West2East Pipeline LLC from October 21, 2005 until June 30,

2006, and we included its results in our consolidated financial statements

until June 30, 2006. On June 30, 2006, our ownership interest was reduced

to 51%, West2East Pipeline LLC was deconsolidated, and we subsequently

accounted for our investment under the equity method of accounting.

(4) Arose from our Vopak terminal acquisition in July 2001. Nassau County,

Florida Ocean Highway and Port Authority is a political subdivision of the

State of Florida. During 1990, Ocean Highway and Port Authority issued its

Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5

million for the purpose of constructing certain port improvements located

in Fernandino Beach, Nassau County, Florida. A letter of credit was issued

as security for the Adjustable Demand Revenue Bonds and was guaranteed by

the parent company of Nassau Terminals LLC, the operator of the port

facilities. In July 2002, we acquired Nassau Terminals LLC and became

guarantor under the letter of credit agreement. In December 2002, we issued

a $28 million letter of credit under our credit facilities and the former

letter of credit guarantee was terminated. As of December 31, 2006, the

value of this letter of credit outstanding under our credit facility was

$23.9 million. Principal payments on the bonds are made on the first of

December each year and reductions are made to the letter of credit.

(5) Principally property, plant and equipment.

(6) Represents the portion of the entity's debt that we may be responsible for

if the entity cannot satisfy the obligation.

We account for our investments in Cortez Pipeline Company, Red Cedar

Gathering Company and West2East Pipeline LLC under the equity method of

accounting. For the year ended December 31, 2006, our share of earnings, based

on our ownership percentage and before amortization of excess investment cost

was $19.2 million from

<PAGE>

Cortez Pipeline Company, $36.3 million from Red Cedar Gathering Company, and

$1.9 million from West2East Pipeline LLC. Additional information regarding the

nature and business purpose of these investments is included in Notes 7 and 9 to

our consolidated financial statements included elsewhere in this report.

Summary of Certain Contractual Obligations

<TABLE>

Amount of Commitment Expiration per Period

----------------------------------------------------------------

1 Year After 5

Total or Less 2-3 Years 4-5 Years Years

---------- ---------- ---------- ---------- -----------

(In thousands)

Contractual Obligations:

Commercial paper outstanding............... $1,098,192 $1,098,192 $ -- $ -- $ --

Other debt borrowings-principal payments... 4,654,476 260,899 267,763 969,494 3,156,320

Interest payments(a)....................... 3,922,682 349,792 547,492 469,117 2,556,281

Lease obligations(b)....................... 157,668 47,882 50,578 30,339 28,869

Post-retirement welfare plans(c)........... 3,709 363 729 727 1,890

Other obligations(d)....................... 155,184 47,391 60,770 39,972 7,051

---------- ---------- ---------- ---------- -----------

Total...................................... $9,991,911 $1,804,519 $ 927,332 $1,509,649 $ 5,750,411

========== ========== ========== ========== ===========

Other commercial commitments:

Standby letters of credit(e)............... $ 445,793 $ 387,579 $ 20,224 $ 490 $ 37,500

========== ========== ========== ========== ==========

Capital expenditures(f).................... $ 85,955 $ 85,955 - - -

========== ========== ========== ========== ===========

-------------

</TABLE>

(a) Interest payment obligations exclude adjustments for interest rate swap

agreements.

(b) Represents commitments for capital leases, including interest, and

operating leases.

calculations of independent enrolled actuary as of December 31, 2006.

(d) Consist of payments due under carbon dioxide take-or-pay contracts, carbon

dioxide removal contracts, natural gas liquids joint tariff agreements and,

for the 1 Year or Less column only, our purchase and sale agreement with

Trans-Global Solutions, Inc. for the acquisition of our Texas Petcoke

terminal assets.

(e) The $445.8 million in letters of credit outstanding as of December 31 2006

consisted of the following: (i) a combined $243 million in three letters of

credit supporting our hedging of commodity price risks; (ii) a combined

$39.7 million in two letters of credit supporting the construction of our

Kinder Morgan Louisiana Pipeline; (iii) a $37.5 million letter of credit

supporting our indemnification obligations on the Series D note borrowings

of Cortez Capital Corporation; (iv) our $30.3 million guarantee under

letters of credit supporting our International Marine Terminals Partnership

Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a

$25.4 million letter of credit supporting our Kinder Morgan Liquids

Terminals LLC New Jersey Economic Development Revenue Bonds; (vi) a $24.1

million letter of credit supporting our Kinder Morgan Operating L.P. "B"

tax-exempt bonds; (vii) a $23.9 million letter of credit supporting Nassau

County, Florida Ocean Highway and Port Authority tax-exempt bonds; (viii) a

$5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois

Development Revenue Bonds; and (ix) a combined $16.5 million in seven

letters of credit supporting environmental and other obligations of us and

our subsidiaries.

(f) Represents commitments for the purchase of plant, property and equipment as

of December 31, 2006.

Operating Activities

Net cash provided by operating activities was $1,257.4 million in 2006,

versus $1,289.4 million in 2005. The year-to-year decrease of $32.0 million (2%)

in cash flow from operations primarily consisted of the following:

o a $125.0 million decrease in cash inflows relative to net changes in

working capital items, mainly due to timing differences that resulted

in higher net cash payments of $159.2 million with regard to the

collection and payment of both trade and related party receivables and

payables;

o a $19.1 million decrease in cash related to payments made in June 2006

to certain shippers on our Pacific operations' pipelines. 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 our

<PAGE>

Pacific operations' Watson Station, located in Carson, California. The

agreement called for estimated refunds to be paid into an escrow

account pending final approval by the FERC, which was made in the

third quarter of 2006;

o a $104.4 million increase in cash from overall higher partnership

income--net of non-cash items including depreciation charges,

undistributed earnings from equity investments, non-cash pipeline

transportation rate case expenses, and gains from both the sale of

assets and property casualty settlements. The higher partnership

income reflects an increase in cash earnings from our four reportable

business segments in 2006, as discussed above in "-Results of

Operations." The components of this overall $104.4 million increase in

operating cash inflows in 2006 compared to 2005 consisted of the

following:

o a $159.9 million increase from higher overall net income;

o a $63.9 million increase from higher non-cash depreciation, depletion

and amortization expenses;

o a $15.5 million increase from higher non-cash earnings from our

unconsolidated investees accounted for under the equity method of

accounting;

o a $105.0 million decrease from the 2005 non-cash operating expense

attributable to an increase in our reserves related to our Pacific

operations' rate case liability; and

o a $29.9 million decrease from non-cash property-related gains and

losses-- primarily consisting of the $15.1 million gain from the

combined sale of our Douglas natural gas gathering system and Painter

Unit fractionation facility and the $15.2 million gain from property

casualty indemnifications, both recognized in 2006;

o a $4.8 million increase related to higher distributions received from

equity investments--chiefly due to higher distributions received from

Red Cedar Gathering Company in 2006, when compared to 2005. The

overall increase in distributions was partially offset by lower

distributions from Plantation Pipe Line Company, due to lower overall

partnership net income in 2006 versus 2005. The increase in

distributions received from Red Cedar was due primarily to higher

year-over-year net income in 2006 versus 2005, and also from the fact

that Red Cedar had higher capital expansion spending in 2005, and

funded a large portion of the expenditures with retained cash; and

o a $2.9 million increase in cash inflows relative to changes in

non-current assets and liabilities--which represent offsetting changes

in cash from various long-term assets and liability accounts.

Investing Activities

Net cash used in investing activities was $1,388.2 million for the year

ended December 31, 2006, compared to $1,181.1 million for the prior year. The

$207.1 million (18%) overall increase in funds utilized in investing activities

was mainly attributable to:

o a $195.2 million (23%) increase in capital expenditures--driven by a

$168.7 million increase in capital spending from our Natural Gas

Pipelines business segment, largely due to the inclusion of Rockies

Express Pipeline LLC's capital expenditures for the first six months

of 2006, and by incremental expenditures for both asset infrastructure

expansions and hurricane repair and replacement costs. We continue to

make significant investments for both strategic acquisitions and

internal growth projects, and including all expansion and maintenance

projects, our capital expenditures were $1,058.3 million in 2006,

compared to $863.1 million in 2005.

Our sustaining capital expenditures totaled $125.4 million in 2006 and

$140.8 million in 2005. Sustaining capital expenditures are defined as

capital expenditures which do not increase the capacity of an asset.

Beginning in the third quarter of 2006, our Products Pipelines and CO2

business segments and our Texas intrastate natural gas pipeline group

began recognizing certain costs incurred as part of their pipeline

integrity management program as maintenance expense in the period

incurred, and in addition, recorded an expense for

<PAGE>

costs previously capitalized as sustaining capital expenditures during

the first six months of 2006. This change primarily affected our

Products Pipelines business segment, reducing its earnings before

depreciation, depletion and amortization expenses by $24.2 million and

reducing its sustaining capital expenditures by $19.8 million, when

compared to 2005.

Additionally, our forecasted expenditures for sustaining capital

expenditures for 2007 are approximately $156.5 million. This amount

has been forecasted primarily for the purchase of plant and equipment.

All of our capital expenditures, with the exception of sustaining

capital expenditures, are discretionary;

o an $89.6 million (29%) increase due to higher expenditures made for

strategic business acquisitions--in 2006, our acquisition outlays

totaled $397.4 million, which primarily consisted of $244.6 million

for the acquisition of Entrega Gas Pipeline LLC and $89.1 million for

the acquisition of bulk, liquids and refined products terminal

operations and related assets. In 2005, our acquisition outlays

totaled $307.8 million, including cash outflows of $188.4 million for

the acquisition of our Texas petroleum coke bulk terminal assets,

$52.9 million for our North Dayton, Texas natural gas storage

facility, and $23.9 million for the acquisition of our Kinder Morgan

Staten Island liquids terminal. Both our 2006 and 2005 acquisition

expenditures are discussed more fully in Note 3 to our consolidated

financial statements included elsewhere in this report;

o a $74.0 million decrease in cash used due to higher net proceeds of

$60.9 million received from both the sales of property, plant and

equipment and other net assets, net of salvage and removal costs, and

$13.1 million from property insurance indemnities received in 2006 for

damaged or destroyed property as a result of the 2005 hurricane

season. The increase from sales proceeds in 2006 versus 2005 was

driven by (i) the $42.5 million we received from Momentum Energy

Group, LLC for the combined sale of our Douglas natural gas gathering

system and Painter Unit fractionation facility; and (ii) the $27.1

million we received from the sale of certain oil and gas properties

originally acquired from Journey Acquisition - I, L.P. and Journey

2000, L.P.; and

o a $5.9 million (31%) decrease due to lower payments for natural gas

stored underground and natural gas liquids pipeline line-fill--largely

related to lower investments in underground natural gas storage

volumes in 2006 compared to 2005.

Financing Activities

Net cash provided by financing activities was $132.4 million in 2006; while

in the prior year, our financing activities used net cash of $96.0 million. The

$228.4 million overall increase in cash inflows provided by financing activities

was primarily due to:

o a $499.1 million increase from overall debt financing

activities--which include our issuances and payments of debt and our

debt issuance costs. The increase was primarily due to a $795.2

million increase from higher net commercial paper borrowings in 2006,

partially offset by a $294.4 million decrease due to both issuances

and payments of senior notes during 2005.

During each of the years 2006 and 2005, we used our commercial paper

borrowings to fund our asset acquisitions, capital expansion projects

and other partnership activities. We subsequently raised funds to

refinance a portion of those borrowings by issuing additional common

units and, in 2005 only, completing public offerings of senior notes.

We used the proceeds from these debt and equity issuances to reduce

our borrowings under our commercial paper program. Furthermore, the

increase in our commercial paper debt includes net borrowings of

$412.5 million under the commercial paper program of Rockies Express

Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express

Pipeline LLC until June 30, 2006, and according to the provisions of

generally accepted accounting principles, we included its cash inflows

and outflows in our consolidated statement of cash flows for the first

six months of 2006.

On June 30, 2006, following ConocoPhillips' acquisition of a 24%

ownership interest in West2East Pipeline LLC (and its subsidiary

Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline

LLC and we have subsequently accounted for our investment under the

equity method of accounting. Following the change to the equity method

on June 30, 2006, Rockies Express' debt balances were no longer

included in our

<PAGE>

consolidated balance sheet and its cash inflows and outflows for all

periods subsequent to June 2006 were not included in our consolidated

statement of cash flows.

The decrease in cash inflows from changes in our senior notes related

to debt activities occurring on March 15, 2005. On that date, we both

closed a public offering of $500 million in principal amount of 5.80%

senior notes and repaid $200 million of 8.0% senior notes that matured

on that date. The 5.80% senior notes are due March 15, 2035. We

received proceeds from the issuance of the notes, after underwriting

discounts and commissions, of approximately $494.4 million, and we

used the proceeds to repay the 8.0% senior notes and to reduce our

commercial paper debt;

o a $102.0 million increase from contributions from minority

interests--principally due to contributions of $104.2 million received

in 2006 from Sempra Energy with regard to its ownership interest in

Rockies Express Pipeline LLC. The contribution from Sempra included an

amount of $80 million, contributed in the first quarter of 2006, for

Sempra's original 33 1/3% share of the purchase price of Entrega Gas

Pipeline LLC. 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;

o a $15.3 million increase from net changes in cash book

overdrafts--which represent checks issued but not yet endorsed. The

increase reflects a higher amount of outstanding checks in 2006, due

to timing differences in the payments of year-end accruals and

outstanding vendor invoices in 2006 versus 2005;

o a $221.6 million decrease from higher partnership

distributions--distributions to all partners, consisting of our common

and Class B unitholders, our general partner and minority interests,

totaled $1,171.5 million in 2006, compared to $949.9 million in 2005.

The overall increase in period-to-period distributions included

minority interest distributions of $105.2 million paid from our

Rockies Express Pipeline LLC subsidiary to Sempra Energy in the first

half of 2006. The distributions to Sempra (and distributions to us for

our proportionate ownership interest) were made in conjunction with

Rockies Express' establishment of and subsequent borrowings under its

commercial paper program during the second quarter of 2006, as

discussed above. During the second quarter of 2006, Rockies Express

both issued a net amount of $412.5 million of commercial paper and

distributed $315.5 million to its member owners. Prior to the

establishment of its commercial paper program (supported by its

five-year unsecured revolving credit agreement), Rockies Express

funded its acquisition of Entrega Gas Pipeline LLC and its Rockies

Express Pipeline construction costs with contributions from both us

and Sempra.

Excluding the minority interest distributions to Sempra, overall

distributions increased $116.4 million in 2006, when compared to 2005.

The increase primarily resulted from higher distributions of

"Available Cash," as described below in "--Partnership Distributions."

The increase in "Available Cash" distributions in 2006 versus 2005 was

due to an increase in the per unit cash distributions paid, an

increase in the number of units outstanding and an increase in our

general partner incentive distributions. We paid distributions of

$3.23 per unit in 2006 compared to $3.07 per unit in 2005. The 5%

increase in distributions paid per unit principally resulted from

favorable operating results in 2006. The increase in our general

partner incentive distributions resulted from both increased cash

distributions per unit and an increase in the number of common units

and i-units outstanding.

We also distributed 4,383,303 and 3,760,732 i-units in quarterly

distributions during 2006 and 2005, respectively, to KMR, our sole

i-unitholder. The amount of i-units distributed in each quarter was

based upon the amount of cash we distributed to the owners of our

common and Class B units during that quarter of 2006 and 2005. For

each outstanding i-unit that KMR held, a fraction of an i-unit was

issued. The fraction was determined by dividing the cash amount

distributed per common unit by the average of KMR's shares' closing

market prices for the ten consecutive trading days preceding the date

on which the shares began to trade ex-dividend under the rules of the

New York Stock Exchange; and

o a $167.2 million decrease in cash inflows from common unit equity

issuances--primarily related to the incremental cash we received from

our two separate 2005 common unit issuances over the cash received

from

<PAGE>

our single 2006 common unit issuance. In both 2006 and 2005, we used

the proceeds from each of these issuances to reduce the borrowings

under our commercial paper program.

In an August 2006 public offering, we issued an additional 5,750,000

of our common units at a price of $44.80, less commissions and

underwriting expenses. After all fees, we received net proceeds of

$248.0 million for the issuance of these common units. In 2005, we

received aggregate proceeds of $413.7 million from two separate common

unit equity issuances, consisting of the following (amounts are net of

all commissions and underwriting expenses):

o $283.6 million received from our issuance of 5,750,000 common

units in an August 2005 public offering; and

o $130.1 million received from our issuance of 2,600,000 common

units in a November 2005 public offering.

Partnership Distributions

Our partnership agreement requires that we distribute 100% of "Available

Cash," as defined in our partnership agreement, to our partners within 45 days

following the end of each calendar quarter in accordance with their respective

percentage interests. Available Cash consists generally of all of our cash

receipts, including cash received by our operating partnerships and net

reductions in reserves, less cash disbursements and net additions to reserves

and amounts payable to the former general partner of SFPP, L.P. in respect of

its remaining 0.5% interest in SFPP.

Our general partner is granted discretion by our partnership agreement,

which discretion has been delegated to KMR, subject to the approval of our

general partner in certain cases, to establish, maintain and adjust reserves for

future operating expenses, debt service, maintenance capital expenditures, rate

refunds and distributions for the next four quarters. These reserves are not

restricted by magnitude, but only by type of future cash requirements with which

they can be associated. When KMR determines our quarterly distributions, it

considers current and expected reserve needs along with current and expected

cash flows to identify the appropriate sustainable distribution level. For 2006,

2005 and 2004, we distributed approximately 103%, 101% and 96%, respectively, of

the total of cash receipts less cash disbursements (calculations assume that KMR

unitholders received cash). The difference between these numbers and 100% of

distributable cash flow reflects net changes in reserves.

Our general partner and owners of our common units and Class B units

receive distributions in cash, while KMR, the sole owner of our i-units,

receives distributions in additional i-units. We do not distribute cash to

i-unit owners but retain the cash for use in our business. However, the cash

equivalent of distributions of i-units is treated as if it had actually been

distributed for purposes of determining the distributions to our general

partner. Each time we make a distribution, the number of i-units owned by KMR

and the percentage of our total units owned by KMR increase automatically under

the provisions of our partnership agreement.

Available cash is initially distributed 98% to our limited partners and 2%

to our general partner. These distribution percentages are modified to provide

for incentive distributions to be paid to our general partner in the event that

quarterly distributions to unitholders exceed certain specified targets.

Available cash for each quarter is distributed:

o first, 98% to the owners of all classes of units pro rata and 2% to

our general partner until the owners of all classes of units have

received a total of $0.15125 per unit in cash or equivalent i-units

for such quarter;

o second, 85% of any available cash then remaining to the owners of all

classes of units pro rata and 15% to our general partner until the

owners of all classes of units have received a total of $0.17875 per

unit in cash or equivalent i-units for such quarter;

o third, 75% of any available cash then remaining to the owners of all

classes of units pro rata and 25% to our general partner until the

owners of all classes of units have received a total of $0.23375 per

unit in cash or equivalent i-units for such quarter; and

<PAGE>

o fourth, 50% of any available cash then remaining to the owners of all

classes of units pro rata, to owners of common units and Class B units

in cash and to owners of i-units in the equivalent number of i-units,

and 50% to our general partner.

Incentive distributions are generally defined as all cash distributions

paid to our general partner that are in excess of 2% of the aggregate value of

cash and i-units being distributed. Our general partner's incentive distribution

that we declared for 2006 was $508.3 million, while the incentive distribution

paid to our general partner during 2006 was $515.9 million. The difference

between declared and paid distributions is due to the fact that our

distributions for the fourth quarter of each year are declared and paid in the

first quarter of the following year.

Under the terms of our partnership agreement, our distributions to

unitholders for 2006 required incentive distributions to our general partner in

the amount of $528.4 million; however, due to the fact that we did not meet our

2006 budget target, we had no obligation to fund our 2006 bonus plan for the

executive officers of our general partner and KMR, and for the employees of KMGP

Services Company, Inc. and KMI who operate our businesses. The board of

directors of KMI determined that it was in KMI's long-term interest to fund a

partial payout of our bonuses through a reduction in the general partner's

incentive distribution and accordingly, our general partner, with the approval

of the compensation committees and boards of KMI and KMR, waived $20.1 million

of its 2006 incentive distribution for the fourth quarter of 2006. The waived

amount approximates an amount equal to our actual bonus payout for 2006, which

is approximately 75% of our budgeted full bonus payout for 2006 of $26.5

million. Including the effect of this waiver, our distributions to unitholders

for 2006 resulted in payments of incentive distributions to our general partner

in the amount of $508.3 million.

On February 14, 2007, we paid a quarterly distribution of $0.83 per unit

for the fourth quarter of 2006. This distribution was 4% greater than the $0.80

distribution per unit we paid for the fourth quarter of 2005 and 2% greater than

the $0.81 distribution per unit we paid for the first quarter of 2006. We paid

this distribution in cash to our common unitholders and to our Class B

unitholders. KMR, our sole i-unitholder, received additional i-units based on

the $0.83 cash distribution per common unit. We believe that future operating

results will continue to support similar levels of quarterly cash and i-unit

distributions; however, no assurance can be given that future distributions will

continue at such levels.

Litigation and Environmental

As of December 31, 2006, we have recorded a total reserve for environmental

claims, without discounting and without regard to anticipated insurance

recoveries, in the amount of $61.6 million. In addition, we have recorded a

receivable of $27.0 million for expected cost recoveries that have been deemed

probable. The reserve is primarily established to address and clean up soil and

ground water impacts from former releases to the environment at facilities we

have acquired or accidental spills or releases at facilities that we own.

Reserves for each project are generally established by reviewing existing

documents, conducting interviews and performing site inspections to determine

the overall size and impact to the environment. Reviews are made on a quarterly

basis to determine the status of the cleanup and the costs associated with the

effort. In assessing environmental risks in conjunction with proposed

acquisitions, we review records relating to environmental issues, conduct site

inspections, interview employees, and, if appropriate, collect soil and

groundwater samples.

Additionally, as of December 31, 2006, we have recorded a total reserve for

legal fees, transportation rate cases and other litigation liabilities in the

amount of $112.0 million. The reserve is primarily related to various claims

from lawsuits arising from our Pacific operations' pipeline transportation

rates, and the contingent amount is based on both the circumstances of

probability and reasonability of dollar estimates. We regularly assess the

likelihood of adverse outcomes resulting from these claims in order to determine

the adequacy of our liability provision. As of December 31, 2005, our total

reserve for legal fees, transportation rate cases and other litigation

liabilities amounted to $136.5 million.

Though no assurance can be given, we believe we have established adequate

environmental and legal reserves such that the resolution of pending

environmental matters and litigation will not have a material adverse impact on

our business, cash flows, financial position or results of operations.

<PAGE>

Pursuant to our continuing commitment to operational excellence and our

focus on safe, reliable operations, we have implemented, and intend to implement

in the future, enhancements to certain of our operational practices in order to

strengthen our environmental and asset integrity performance. These enhancements

have resulted and may result in higher operating costs and sustaining capital

expenditures; however, we believe these enhancements will provide us the greater

long term benefits of improved environmental and asset integrity performance.

Please refer to Notes 16 and 17, respectively, to our consolidated

financial statements included elsewhere in this report for additional

information regarding pending litigation, environmental and asset integrity

matters.

Regulation

The Pipeline Safety Improvement Act of 2002 requires pipeline companies to

perform integrity tests on natural gas transmission pipelines that exist in

high population density areas that are designated as High Consequence Areas.

Pipeline companies are required to perform the integrity tests within ten

years of December 17, 2002, the date of enactment, and must perform

subsequent integrity tests on a seven year cycle. At least 50% of the

highest risk segments must be tested within five years of the enactment

date. The risk ratings are based on numerous factors, including the

population density in the geographic regions served by a particular pipeline,

as well as the age and condition of the pipeline and its protective coating.

Testing will consist of hydrostatic testing, internal electronic testing, or

direct assessment of the piping. A similar integrity management rule for

refined petroleum products pipelines became effective May 29, 2001. All

baseline assessments for products pipelines must be completed by March 31,

2008. We have included all incremental expenditures estimated to occur

during 2007 associated with the Pipeline Safety Improvement Act of 2002 and

the integrity management of our products pipelines in our 2007 budget and

capital expenditure plan.

Please refer to Note17 to our consolidated financial statements included

elsewhere in this report for additional information regarding regulatory

matters.

Recent Accounting Pronouncements

Please refer to Note 18 to our consolidated financial statements included

elsewhere in this report for information concerning recent accounting

pronouncements.

Information Regarding Forward-Looking Statements

This filing includes forward-looking statements. These forward-looking

statements are identified as any statement that does not relate strictly to

historical or current facts. They use words such as "anticipate," "believe,"

"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"

"estimate," "expect," "may," or the negative of those terms or other variations

of them or comparable terminology. In particular, statements, express or

implied, concerning future actions, conditions or events, future operating

results or the ability to generate sales, income or cash flow or to make

distributions are forward-looking statements. Forward-looking statements are not

guarantees of performance. They involve risks, uncertainties and assumptions.

Future actions, conditions or events and future results of operations may differ

materially from those expressed in these forward-looking statements.

Many of the factors that will determine these results are beyond our ability to

control or predict. Specific factors which could cause actual results to differ

from those in the forward-looking statements include:

o price trends and overall demand for natural gas liquids, refined

petroleum products, oil, carbon dioxide, natural gas, coal and other

bulk materials and chemicals in North America;

o economic activity, weather, alternative energy sources, conservation

and technological advances that may affect price trends and demand;

o changes in our tariff rates implemented by the Federal Energy

Regulatory Commission or the California Public Utilities Commission;

o our ability to acquire new businesses and assets and integrate those

operations into our existing operations, as well as our ability to

make expansions to our facilities;

<PAGE>

o difficulties or delays experienced by railroads, barges, trucks, ships

or pipelines in delivering products to or from our terminals or

pipelines;

o our ability to successfully identify and close acquisitions and make

cost-saving changes in operations;

o shut-downs or cutbacks at major refineries, petrochemical or chemical

plants, ports, utilities, military bases or other businesses that use

our services or provide services or products to us;

o crude oil and natural gas production from exploration and production

areas that we serve, including, among others, the Permian Basin area

of West Texas;

o changes in laws or regulations, third-party relations and approvals,

decisions of courts, regulators and governmental bodies that may

adversely affect our business or our ability to compete;

o changes in accounting pronouncements that impact the measurement of

our results of operations, the timing of when such measurements are to

be made and recorded, and the disclosures surrounding these

activities;

o our ability to offer and sell equity securities and debt securities or

obtain debt financing in sufficient amounts to implement that portion

of our business plan that contemplates growth through acquisitions of

operating businesses and assets and expansions of our facilities;

o our indebtedness could make us vulnerable to general adverse economic

and industry conditions, limit our ability to borrow additional funds,

and/or place us at competitive disadvantages compared to our

competitors that have less debt or have other adverse consequences;

o interruptions of electric power supply to our facilities due to

natural disasters, power shortages, strikes, riots, terrorism, war or

other causes;

o our ability to obtain insurance coverage without significant levels of

self-retention of risk;

o acts of nature, sabotage, terrorism or other similar acts causing

damage greater than our insurance coverage limits;

o capital markets conditions;

o the political and economic stability of the oil producing nations of

the world;

o national, international, regional and local economic, competitive and

regulatory conditions and developments;

o the ability to achieve cost savings and revenue growth;

o inflation;

o interest rates;

o the pace of deregulation of retail natural gas and electricity;

o foreign exchange fluctuations;

o the timing and extent of changes in commodity prices for oil, natural

gas, electricity and certain agricultural products;

o the extent of our success in discovering, developing and producing oil

and gas reserves, including the risks inherent in exploration and

development drilling, well completion and other development

activities;

100

<PAGE>

o engineering and mechanical or technological difficulties with

operational equipment, in well completions and workovers, and in

drilling new wells;

o the uncertainty inherent in estimating future oil and natural gas

production or reserves;

o the ability to complete expansion projects on time and on budget;

o the timing and success of business development efforts; and

o unfavorable results of litigation and the fruition of contingencies

referred to in Note 3 to our consolidated financial statements

included elsewhere in this report.

There is no assurance that any of the actions, events or results of the

forward-looking statements will occur, or if any of them do, what impact they

will have on our results of operations or financial condition. Because of these

uncertainties, you should not put undue reliance on any forward-looking

statements.

See Item 1A "Risk Factors" for a more detailed description of these and

other factors that may affect the forward-looking statements. When considering

forward-looking statements, one should keep in mind the risk factors described

in "Risk Factors" above. The risk factors could cause our actual results to

differ materially from those contained in any forward-looking statement. Other

than as required by applicable law, we disclaim any obligation to update the

above list or to announce publicly the result of any revisions to any of the

forward-looking statements to reflect future events or developments.

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

Generally, our market risk sensitive instruments and positions have been

determined to be "other than trading." Our exposure to market risk as discussed

below includes forward-looking statements and represents an estimate of possible

changes in fair value or future earnings that would occur assuming hypothetical

future movements in interest rates or commodity prices. Our views on market risk

are not necessarily indicative of actual results that may occur and do not

represent the maximum possible gains and losses that may occur, since actual

gains and losses will differ from those estimated, based on actual fluctuations

in commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

We are exposed to commodity market risk and other external risks, such as

weather-related risk, in the ordinary course of business. However, we take steps

to hedge, or limit our exposure to, these risks in order to maintain a more

stable and predictable earnings stream. Stated another way, we execute a hedging

strategy that seeks to protect our financial position against adverse price

movements and serves to minimize potential losses. Our strategy involves the use

of certain energy commodity derivative contracts to reduce and minimize the

risks associated with unfavorable changes in the market price of natural gas,

natural gas liquids and crude oil. The derivative contracts we use include

energy products traded on the New York Mercantile Exchange and over-the-counter

markets, including, but not limited to, futures and options contracts, fixed

price swaps and basis swaps.

Fundamentally, our hedging strategy involves taking a simultaneous position

in the futures market that is equal and opposite to our position in the cash

market (or physical product) in order to minimize the risk of financial loss

from an adverse price change. For example, as sellers of crude oil and natural

gas, we often enter into fixed price swaps and/or futures contracts to guarantee

or lock-in the sale price of our oil or the margin from the sale and purchase of

our natural gas at the time of market delivery, thereby directly offsetting any

change in prices, either positive or negative. A hedge is successful when gains

or losses in the cash market are neutralized by losses or gains in the futures

transaction.

Our risk management policies prohibit us from engaging in speculative

trading and we are not a party to leveraged derivatives. Furthermore, our

policies require that we only enter into derivative contracts with carefully

selected major financial institutions or similar counterparties based upon their

credit ratings and other factors, and

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we maintain strict dollar and term limits that correspond to our counterparties'

credit ratings. While we enter into derivative transactions only with investment

grade counterparties and actively monitor their credit ratings, it is

nevertheless possible that losses will result from counterparty credit risk in

the future. The credit ratings of the primary parties from whom we purchase

energy commodity derivative contracts are as follows:

Credit Rating

-------------

Morgan Stanley................................. A+

J. Aron & Company / Goldman Sachs.............. AA-

BNP Paribas.................................... AA

We account for our energy commodity risk management derivative contracts

according to the provisions of Statement of Financial Accounting Standards No.

133, "Accounting for Derivative Instruments and Hedging Activities" (after

amendment by SFAS No. 137, SFAS No. 138, and SFAS No. 149). According to the

provisions of SFAS No. 133, derivatives are measured at fair value and

recognized on the balance sheet as either assets or liabilities, and in general,

gains and losses on derivatives are reported on the income statement. However,

as discussed above, our principal use of energy commodity derivative contracts

is to mitigate the market price risk associated with anticipated transactions

for the purchase and sale of natural gas, natural gas liquids and crude oil.

Using derivative contracts to help provide us certainty with regard to our

operating cash flows helps us undertake further capital improvement projects,

attain budget results and meet distribution targets to our partners.

SFAS No. 133 categorizes such use of energy commodity derivative contracts

as cash flow hedges because the derivative contract is used to hedge the

anticipated future cash flow of a transaction that is expected to occur but

whose value is uncertain. Cash flow hedges are defined as hedges made with the

intention of decreasing the variability in cash flows related to future

transactions, as opposed to the value of an asset, liability or firm commitment,

and SFAS No. 133 prescribes special hedge accounting treatment for such

derivatives.

In accounting for cash flow hedges, gains and losses on the derivative

contracts are reported in other comprehensive income, outside "Net Income"

reported in our consolidated statements of income, but only to the extent that

the gains and losses from the change in value of the derivative contracts can

later offset the loss or gain from the change in value of the hedged future cash

flows during the period in which the hedged cash flows affect net income. That

is, for cash flow hedges, all effective components of the derivative contracts'

gains and losses goes to other comprehensive income, pending occurrence of the

expected transaction. Other comprehensive income consists of those financial

items that are included in "Accumulated other comprehensive loss" in our

accompanying consolidated balance sheets but not included in our net income.

Thus, in highly effective cash flow hedges, where there is no ineffectiveness,

other comprehensive income changes by exactly as much as the derivative

contracts and there is no impact on earnings.

All remaining gains and losses on the derivative contracts (the ineffective

portion) are included in current net income. The ineffective portion of the gain

or loss on the derivative contracts is the difference between the gain or loss

from the change in value of the derivative contract and the effective portion of

that gain or loss. In addition, when the hedged forecasted transaction does take

place and affects earnings, the effective part of the hedge is also recognized

in the income statement, and the earlier recognized effective amounts are

removed from "Accumulated other comprehensive loss." If the forecasted

transaction results in an asset or liability, amounts in "Accumulated other

comprehensive loss" should be reclassified into earnings when the asset or

liability affects earnings through cost of sales, depreciation, interest

expense, etc.

Under current accounting rules, the accumulated components of other

comprehensive income are to be reported separately as accumulated other

comprehensive income or loss in the stockholders' equity section of the balance

sheet. Accordingly, our application of SFAS No. 133 has resulted in deferred net

loss amounts of $838.7 million and $1,079.4 million being included within

"Accumulated other comprehensive loss" in the Partners' Capital section of our

accompanying balance sheets as of December 31, 2006 and December 31, 2005,

respectively.

For us, the gains and losses that are included in "Accumulated other

comprehensive loss" in our accompanying consolidated balance sheets are

primarily related to the derivative contracts associated with our hedging of

anticipated future cash flows from the sales and purchases of natural gas,

natural gas liquids and crude oil and represent the effective portion of the

gain or loss on these derivative contacts. In future periods, as the hedged cash

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flows from our actual purchases and sales of energy commodities affect our net

income, the related gains and losses included in our accumulated other

comprehensive loss as a result of our hedging are transferred to the income

statement as well, effectively offsetting the changes in cash flows stemming

from the hedged risk.

We measure the risk of price changes in the natural gas, natural gas

liquids and crude oil markets utilizing a value-at-risk model. Value-at-risk is

a statistical measure of how much the mark-to-market value of a portfolio could

change during a period of time, within a certain level of statistical

confidence. We utilize a closed form model to evaluate risk on a daily basis.

The value-at-risk computations utilize a confidence level of 97.7% for the

resultant price movement and a holding period of one day is chosen for the

calculation. The confidence level used means that there is a 97.7% probability

that the mark-to-market losses for a single day will not exceed the

value-at-risk number presented. Derivative contracts evaluated by the model

include commodity futures and options contracts, fixed price swaps, basis swaps

and over-the-counter options.

For each of the years ended December 31, 2006 and 2005, value-at-risk

reached a high of $2.6 million and $21.5 million, respectively, and a low of

$0.5 million and $7.6 million, respectively. Value-at-risk as of December 31,

2006, was $0.6 million and averaged $1.1 million for 2006. Value-at-risk as of

December 31, 2005, was $9.1 million and averaged $12.7 million for 2005.

Our calculated value-at-risk exposure represents an estimate of the

reasonably possible net losses that would be recognized on our portfolio of

derivative contracts assuming hypothetical movements in future market rates, and

is not necessarily indicative of actual results that may occur. It does not

represent the maximum possible loss or any expected loss that may occur, since

actual future gains and losses will differ from those estimated. Actual gains

and losses may differ from estimates due to actual fluctuations in market rates,

operating exposures and the timing thereof, as well as changes in our portfolio

of derivatives during the year. In addition, as discussed above, we enter into

these derivative contracts solely for the purpose of mitigating the risks that

accompany certain of our business activities and, therefore, the change in the

market value of our portfolio of derivative contracts, with the exception of a

minor amount of hedging inefficiency, is offset by changes in the value of the

underlying physical transactions. For more information on our risk management

activities, see Note 14 to our consolidated financial statements included

elsewhere in this report.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy

to borrow funds using a mix of fixed rate debt and variable rate debt. The

market risk inherent in our debt instruments and positions is the potential

change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in interest rates generally affect the fair

value of the debt instrument, but not our earnings or cash flows. Conversely,

for variable rate debt, changes in interest rates generally do not impact the

fair value of the debt instrument, but may affect our future earnings and cash

flows. We do not have an obligation to prepay fixed rate debt prior to maturity

and, as a result, interest rate risk and changes in fair value should not have a

significant impact on our fixed rate debt until we would be required to

refinance such debt.

As of December 31, 2006 and 2005, the carrying values of our fixed rate

debt were approximately $4,551.2 million and $4,560.7 million, respectively.

These amounts compare to, as of December 31, 2006 and 2005, fair values of

$4,672.7 million and $4,805.0 million, respectively. Fair values were determined

using quoted market prices, where applicable, or future cash flow discounted at

market rates for similar types of borrowing arrangements. A hypothetical 10%

change (approximately 62 basis points) in the average interest rates applicable

to such debt for 2006 and 2005, respectively, would result in changes of

approximately $183.4 million and $193.8 million, respectively, in the fair

values of these instruments.

The carrying value and fair value of our variable rate debt, including

associated accrued interest and excluding market value of interest rate swaps,

was $1,195.6 million as of December 31, 2006 and $655.9 million as of December

31, 2005. A hypothetical 10% change in the weighted average interest rate on all

of our borrowings, when applied to our outstanding balance of variable rate debt

as of December 31, 2006 and 2005, respectively, including adjustments for

notional swap amounts, would result in changes of approximately $20.3 million

and $13.9 million, respectively, in our 2006 and 2005 annual pre-tax earnings.

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As of both December 31, 2006 and 2005, we were a party to interest rate

swap agreements with notional principal amounts of $2.1 billion. An interest

rate swap agreement is a contractual agreement entered into between two

counterparties under which each agrees to make periodic interest payments to the

other for an agreed period of time based upon a predetermined amount of

principal, which is called the notional principal amount. Normally at each

payment or settlement date, the party who owes more pays the net amount; so at

any given settlement date only one party actually makes a payment. The principal

amount is notional because there is no need to exchange actual amounts of

principal.

We entered into our interest rate swap agreements for the purposes of:

o hedging the interest rate risk associated with our fixed rate debt

obligations; and

o transforming a portion of the underlying cash flows related to our

long-term fixed rate debt securities into variable rate debt in order

to achieve our desired mix of fixed and variable rate debt.

Since the fair value of our fixed rate debt varies with changes in the

market rate of interest, we enter into swap agreements to receive a fixed and

pay a variable rate of interest. Such swap agreements result in future cash

flows that vary with the market rate of interest, and therefore hedge against

changes in the fair value of our fixed rate debt due to market rate changes. As

of December 31, 2006, all of our interest rate swap agreements represented

fixed-for-variable rate swaps, where we agreed to pay our counterparties a

variable rate of interest on a notional principal amount of $2.1 billion,

comprised of principal amounts from various series of our long-term fixed rate

senior notes. In exchange, our counterparties agreed to pay us a fixed rate of

interest, thereby allowing us to transform our fixed rate liabilities into

variable rate obligations without the incurrence of additional loan origination

or conversion costs.

We monitor our mix of fixed rate and variable rate debt obligations in

light of changing market conditions and from time to time may alter that mix by,

for example, refinancing balances outstanding under our variable rate debt with

fixed rate debt (or vice versa) or by entering into interest rate swap

agreements or other interest rate hedging agreements. In general, we attempt to

maintain an overall target mix of approximately 50% fixed rate debt and 50%

variable rate debt.

As of December 31, 2006, our cash and investment portfolio did not include

fixed-income securities. Due to the short-term nature of our investment

portfolio, a hypothetical 10% increase in interest rates would not have a

material effect on the fair market value of our portfolio. Since we have the

ability to liquidate this portfolio, we do not expect our operating results or

cash flows to be materially affected to any significant degree by the effect of

a sudden change in market interest rates on our investment portfolio.

See Note 9 to our consolidated financial statements included elsewhere in

this report for additional information related to our debt instruments; for more

information on our interest rate swap agreements, see Note 14.

Item 8. Financial Statements and Supplementary Data.

The information required in this Item 8 is included in this report as set

forth in the "Index to Financial Statements" on page 134.

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

Financial Disclosure.

None.

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Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2006, our management, including our Chief Executive

Officer and Chief Financial Officer, has evaluated the effectiveness of the

design and operation of our disclosure controls and procedures pursuant to Rule

13a-15(b) under the Securities Exchange Act of 1934. There are inherent

limitations to the effectiveness of any system of disclosure controls and

procedures, including the possibility of human error and the circumvention or

overriding of the controls and procedures. Accordingly, even effective

disclosure controls and procedures can only provide reasonable assurance of

achieving their control objectives. Based upon and as of the date of the

evaluation, our Chief Executive Officer and our Chief Financial Officer

concluded that the design and operation of our disclosure controls and

procedures were effective to provide reasonable assurance that information

required to be disclosed in the reports we file and submit under the Securities

Exchange Act of 1934 is recorded, processed, summarized and reported as and when

required, and is accumulated and communicated to our management, including our

Chief Executive Officer and Chief Financial Officer, as appropriate, to allow

timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate

internal control over financial reporting, as such term is defined in Exchange

Act Rule 13a-15(f). Because of its inherent limitations, internal control over

financial reporting may not prevent or detect misstatements. Projections of any

evaluation of effectiveness to future periods are subject to the risk that

controls may become inadequate because of changes in conditions, or that the

degree of compliance with the policies or procedures may deteriorate. Under the

supervision and with the participation of our management, including our Chief

Executive Officer and Chief Financial Officer, we conducted an evaluation of the

effectiveness of our internal control over financial reporting based on the

framework in Internal Control - Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission. Based on our evaluation

under the framework in Internal Control - Integrated Framework, our management

concluded that our internal control over financial reporting was effective as of

December 31, 2006.

Our management's assessment of the effectiveness of our internal control

over financial reporting as of December 31, 2006 has been audited by

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as

stated in their attestation report which is included elsewhere in this report.

Certain businesses we acquired during 2006 were excluded from the scope of

our management's assessment of the effectiveness of our internal control over

financial reporting as of December 31, 2006. The excluded businesses consisted

of the following:

o the various oil and gas properties acquired from Journey Acquisition -

I, L.P. and Journey 2000, L.P. on April 5, 2006. The acquisition was

made effective March 1, 2006;

o 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 all of the

membership interests in Lomita Rail Terminal LLC;

o all of the membership interests of Transload Services, LLC, acquired

November 20, 2006;

o all of the membership interests of Devco USA L.L.C., acquired December

1, 2006; and

o the refined petroleum products terminal located in Roanoke, Virginia,

acquired from Motiva Enterprises, LLC effective December 15, 2006.

These businesses, in the aggregate, constituted 0.4% of our total operating

revenues for 2006 and 1.2% of our total assets as of December 31, 2006.

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Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting

during the fourth quarter of 2006 that has materially affected, or is reasonably

likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Directors and Executive Officers of our General Partner and its Delegate

Set forth below is certain information concerning the directors and

executive officers of our general partner and KMR, the delegate of our general

partner. All directors of our general partner are elected annually by, and may

be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all

directors of KMR are elected annually by, and may be removed by, our general

partner as the sole holder of KMR's voting shares. Kinder Morgan (Delaware),

Inc. is a wholly owned subsidiary of KMI. All officers of the general partner

and all officers of KMR serve at the discretion of the board of directors of our

general partner.

<TABLE>

Name Age Position with our General Partner and KMR

---------------------- ---- ---------------------------------------------

<S> <C>

Richard D. Kinder............ 62 Director, Chairman and Chief Executive Officer

C. Park Shaper............... 38 Director and President

Steven J. Kean............... 45 Executive Vice President and Chief Operating Officer

Edward O. Gaylord............ 75 Director

Gary L. Hultquist............ 63 Director

Perry M. Waughtal............ 71 Director

Kimberly A. Dang............. 37 Vice President, Investor Relations and Chief Financial Officer

Jeffrey R. Armstrong......... 38 Vice President (President, Terminals)

Thomas A. Bannigan........... 53 Vice President (President, Products Pipelines)

Richard T. Bradley........... 51 Vice President (President, CO2)

David D. Kinder.............. 32 Vice President, Corporate Development and Treasurer

Joseph Listengart............ 38 Vice President, General Counsel and Secretary

Scott E. Parker.............. 46 Vice President (President, Natural Gas Pipelines)

James E. Street.............. 50 Vice President, Human Resources and Administration

</TABLE>

Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR,

Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as Director, Chairman

and Chief Executive Officer of KMR since its formation in February 2001. He was

elected Director, Chairman and Chief Executive Officer of KMI in October 1999.

He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan

G.P., Inc. in February 1997. Mr. Kinder was elected President of KMR, Kinder

Morgan G.P., Inc. and KMI in July 2004 and served as President until May 2005.

Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development

and Treasurer of KMR, Kinder Morgan G.P., Inc. and KMI.

C. Park Shaper is Director and President of KMR and Kinder Morgan G.P.,

Inc. and President of KMI. Mr. Shaper was elected President of KMR, Kinder

Morgan G.P., Inc. and KMI in May 2005. He served as Executive Vice President of

KMR, Kinder Morgan G.P., Inc. and KMI from July 2004 until May 2005. Mr. Shaper

was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003. He was

elected Vice President, Treasurer and Chief Financial Officer of KMR upon its

formation in February 2001, and served as its Treasurer until January 2004, and

its Chief Financial Officer until May 2005. He was elected Vice President,

Treasurer and Chief Financial Officer of KMI in January 2000, and served as its

Treasurer until January 2004, and its Chief Financial Officer until May 2005.

Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of

Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until

January 2004, and its Chief Financial Officer until May 2005. He received a

Masters of Business Administration degree from the J.L. Kellogg Graduate School

of Management at Northwestern University. Mr. Shaper also has a Bachelor of

Science degree in Industrial Engineering and a Bachelor of Arts degree in

Quantitative Economics from Stanford University.

Steven J. Kean is Executive Vice President and Chief Operating Officer of

KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kean was elected Executive Vice

President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and KMI

in January 2006. He served as Executive Vice President, Operations of KMR,

Kinder Morgan G.P., Inc. and KMI from May 2005 to January 2006. He served as

President, Texas Intrastate Pipeline Group from June

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2002 until May 2005. He served as Vice President of Strategic Planning for the

Kinder Morgan Gas Pipeline Group from January 2002 until June 2002. Until

December 2001, Mr. Kean was Executive Vice President and Chief of Staff of Enron

Corp. Mr. Kean received his Juris Doctor from the University of Iowa in May 1985

and received a Bachelor of Arts degree from Iowa State University in May 1982.

Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr.

Gaylord was elected Director of KMR upon its formation in February 2001. Mr.

Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since

1989, Mr. Gaylord has been the Chairman of the board of directors of Jacintoport

Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship

channel.

Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr.

Hultquist was elected Director of KMR upon its formation in February 2001. He

was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995,

Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San

Francisco-based strategic and merger advisory firm.

Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr.

Waughtal was elected Director of KMR upon its formation in February 2001. Mr.

Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Since

1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta,

Georgia based real estate investment company. Mr. Waughtal is also a director of

HealthTronics, Inc.

Kimberly A. Dang is Vice President, Investor Relations and Chief Financial

Officer of KMR, Kinder Morgan G.P., Inc. and KMI. Mrs. Dang was elected Chief

Financial Officer of KMR, Kinder Morgan G.P., Inc. and KMI in May 2005. She

served as Treasurer of KMR, Kinder Morgan G.P., Inc. and KMI from January 2004

to May 2005. She was elected Vice President, Investor Relations of KMR, Kinder

Morgan G.P., Inc. and KMI in July 2002. From November 2001 to July 2002, she

served as Director, Investor Relations. From May 2001 until November 2001, Mrs.

Dang was an independent financial consultant. From September 2000 until May

2001, she served as an associate and later a principal at Murphree Venture

Partners, a venture capital firm. Mrs. Dang has received a Masters in Business

Administration degree from the J.L. Kellogg Graduate School of Management at

Northwestern University and a Bachelor of Business Administration degree in

accounting from Texas A&M University.

Jeffrey R. Armstrong is Vice President (President, Terminals) of KMR and

Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President,

Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals

LLC from March 1, 2001, when the company was formed via the acquisition of GATX

Terminals, through July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX

Terminals, where he was General Manager of their East Coast operations. He

received his Bachelor's degree from the United States Merchant Marine Academy

and an MBA from the University of Notre Dame.

Thomas A. Bannigan is Vice President (President, Products Pipelines) of KMR

and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of

Plantation Pipe Line Company. Mr. Bannigan was elected Vice President

(President, Products Pipelines) of KMR upon its formation in February 2001. He

was elected Vice President (President, Products Pipelines) of Kinder Morgan

G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief

Executive Officer of Plantation Pipe Line Company since May 1998. Mr. Bannigan

received his Juris Doctor, cum laude, from Loyola University in 1980 and

received a Bachelors degree from the State University of New York in Buffalo.

Richard T. Bradley is Vice President (President, CO2) of KMR and of Kinder

Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley

was elected Vice President (President, CO2) of KMR upon its formation in

February 2001 and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in

April 2000. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P.

(formerly known as Shell CO2 Company, Ltd.) since March 1998. Mr. Bradley

received a Bachelor of Science in Petroleum Engineering from the University of

Missouri at Rolla.

David D. Kinder is Vice President, Corporate Development and Treasurer of

KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder was elected Treasurer of KMR,

Kinder Morgan G.P., Inc. and KMI in May 2005. He was elected Vice President,

Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002.

He served as manager of corporate development for KMI and Kinder Morgan G.P.,

Inc. from January 2000 to October

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2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from

Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D.

Kinder.

Joseph Listengart is Vice President, General Counsel and Secretary of KMR,

Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President,

General Counsel and Secretary of KMR upon its formation in February 2001. He was

elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice

President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart

was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been

an employee of Kinder Morgan G.P., Inc. since March 1998. Mr. Listengart

received his Masters in Business Administration from Boston University in

January 1995, his Juris Doctor, magna cum laude, from Boston University in May

1994, and his Bachelor of Arts degree in Economics from Stanford University in

June 1990.

Scott E. Parker is Vice President (President, Natural Gas Pipelines) of

KMR, Kinder Morgan G.P., Inc. and KMI. He was elected Vice President (President,

Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI in May 2005. Mr.

Parker served as President of KMI's Natural Gas Pipeline Company of America, or

NGPL, from March 2003 to May 2005. Mr. Parker served as Vice President, Business

Development of NGPL from January 2001 to March 2003. He held various positions

at NGPL from January 1984 to January 2001. Mr. Parker holds a Bachelor's degree

in accounting from Governors State University.

James E. Street is Vice President, Human Resources and Administration of

KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice President,

Human Resources and Administration of KMR upon its formation in February 2001.

He was elected Vice President, Human Resources and Administration of Kinder

Morgan G.P., Inc. and KMI in August 1999. Mr. Street received a Masters of

Business Administration degree from the University of Nebraska at Omaha and a

Bachelor of Science degree from the University of Nebraska at Kearney.

Corporate Governance

We have a separately designated standing audit committee established in

accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934

comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Gaylord is the

chairman of the audit committee and has been determined by the board to be an

"audit committee financial expert." The board has determined that all of the

members of the audit committee are independent as described under the relevant

standards.

We have not, nor has our general partner nor KMR made, within the preceding

three years, contributions to any tax-exempt organization in which any of our or

KMR's independent directors serves as an executive officer that in any single

fiscal year exceeded the greater of $1.0 million or 2% of such tax-exempt

organization's consolidated gross revenues.

On April 11, 2006, our chief executive officer certified to the New York

Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange

Listed Company Manual, that as of April 11, 2006, he was not aware of any

violation by us of the New York Stock Exchange's Corporate Governance listing

standards. We have also filed as an exhibit to this report the Sarbanes-Oxley

Act Section 302 certifications regarding the quality of our public disclosure.

We make available free of charge within the "Investors" information section

of our Internet website, at www.kindermorgan.com, and in print to any unitholder

who requests, the governance guidelines, the charters of the audit committee,

compensation committee and nominating and governance committee, and our code of

business conduct and ethics (which applies to senior financial and accounting

officers and the chief executive officer, among others). Requests for copies may

be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500

Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We

intend to disclose any amendments to our code of business conduct and ethics

that would otherwise be disclosed on Form 8-K and any waiver from a provision of

that code granted to our executive officers or directors that would otherwise be

disclosed on Form 8-K on our Internet website within four business days

following such amendment or waiver. The information contained on or connected to

our Internet website is not incorporated by reference into this Form 10-K and

should not be considered part of this or any other report that we file with or

furnish to the SEC.

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Interested parties may contact our lead director, the chairpersons of any

of the board's committees, the independent directors as a group or the full

board by mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000,

Houston, Texas 77002, Attention: General Counsel, or by e-mail within the

"Contact Us" section of our Internet website, at www.kindermorgan.com. Any

communication should specify the intended recipient.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16 of the Securities Exchange Act of 1934 requires our directors

and officers, and persons who own more than 10% of a registered class of our

equity securities, to file initial reports of ownership and reports of changes

in ownership with the Securities and Exchange Commission. Such persons are

required by SEC regulation to furnish us with copies of all Section 16(a) forms

they file.

Based solely on our review of the copies of such forms furnished to us and

written representations from our executive officers and directors, we believe

that all Section 16(a) filing requirements were met during 2006.

Item 11. Executive Compensation.

As is commonly the case for publicly traded limited partnerships, we have

no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc.,

as our general partner, is to direct, control and manage all of our activities.

Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has

delegated to KMR the management and control of our business and affairs to the

maximum extent permitted by our partnership agreement and Delaware law, subject

to our general partner's right to approve certain actions by KMR. The executive

officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities

for KMR. Certain of those executive officers also serve as executive officers of

KMI. All information in this report with respect to compensation of executive

officers describes the total compensation received by those persons in all

capacities for Kinder Morgan G.P., Inc., KMR, KMI and their respective

affiliates; consequently, in this Item 11., "we," "our" or "us" refers to Kinder

Morgan G.P., Inc., KMR and, where appropriate, KMI.

Compensation Discussion and Analysis

Program Objectives

We are a publicly traded master limited partnership, and our businesses

consist of a diversified portfolio of energy transportation, storage and

production assets. We seek to attract and retain executives who will help us

achieve our primary business strategy objective of growing the value of our

portfolio of businesses for the benefit of our unitholders. To help accomplish

this goal, we have designed an executive compensation program that rewards

individuals with competitive compensation that consists of a mix of cash,

benefit plans and long-term compensation, with a majority of executive

compensation tied to the "at risk" portions of the annual cash bonus and

long-term equity compensation.

The key objectives of our executive compensation program are to attract,

motivate and retain executives who will advance our overall business strategies

and objectives to create and return value to our unitholders. We believe that an

effective executive compensation program should link total compensation to

financial performance and to the attainment of short and long term strategic,

operational, and financial objectives. We also believe it should provide

competitive total compensation opportunities at a reasonable cost. In designing

our executive compensation program, we have recognized that our executives have

a much greater portion of their overall compensation at-risk than do our other

employees; consequently, we have tried to establish the at-risk portions of our

executive total compensation at levels that recognize their much increased level

of responsibility and their ability to influence business results.

Our executive compensation program is principally comprised of the

following three elements:

o base cash salary;

o possible annual cash bonus (reflected in the Summary Compensation

Table below as Non-Equity Incentive Plan Compensation); and

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o possible long-term equity awards, namely grants of restricted KMI

stock and, in previous years, grants of options to acquire shares of

KMI common stock.

It is our current philosophy to pay our executive officers a base salary

not to exceed $200,000 per year, which is below base salaries for comparable

positions in the marketplace. In addition, we believe that the compensation of

our Chief Executive Officer, Chief Financial Officer and the executives named

below, collectively referred to in this Item 11 as our named executive officers,

should be directly and materially tied to the financial performance of KMI and

us, and should be aligned with the interests of KMI stockholders and our

unitholders. Therefore, the majority of our named executive officers'

compensation is allocated to the "at risk" portions of our compensation

program--the annual cash bonus and the long-term equity compensation. For 2006,

our executive compensation was weighted toward the cash bonus, payable on the

basis of achieving (i) an earnings per share target by KMI; and (ii) a cash

distribution per common unit target by us. Prior to 2003, we used both KMI stock

options and restricted KMI stock as the principal components of long-term

executive compensation, and beginning in 2003, we used grants of restricted

stock exclusively as the principal component of long-term executive

compensation.

Grants of restricted KMI stock are made to encourage our executive officers

to manage from the perspective of owners with an equity stake, and our approach

to equity compensation is designed to balance the business objective of fair and

reasonable executive pay with the business objectives of equityholder interests.

We are very sensitive to making large awards of KMI restricted stock or KMI

stock options to our executive officers because such large awards dilute the

ownership of KMI's stockholders. Therefore, we seek to balance the dilutive

effect of such stock awards to KMI's existing stockholders with our need to

attract and retain key employees.

Additionally, we periodically compare our executive compensation components

with market information. The purpose of this comparison is to ensure that our

total compensation package operates effectively, remains both reasonable and

competitive with the energy industry, and is generally comparable to the

compensation offered by companies of similar size and scope as us. We also keep

abreast of current trends, developments, and emerging issues in executive

compensation, and if appropriate, will obtain advice and assistance from outside

legal, compensation or other advisors.

We have endeavored to design our executive compensation program and

practices with appropriate consideration of all tax, accounting, legal and

regulatory requirements. Section 162(m) of the Internal Revenue Code limits the

deductibility of certain compensation for our executive officers to $1,000,000

of compensation per year; however, if specified conditions are met, certain

compensation may be excluded from consideration of the $1,000,000 limit. Since

the bonuses we pay to our executive officers are paid under KMI's

stockholder-approved 2005 Annual Incentive Plan as a result of reaching

designated financial targets established by KMI's compensation committee, we

expect that all compensation paid to our executives will be deductible by KMI.

Behaviors Designed to Reward

Our executive compensation program is designed to reward individuals for

advancing our business strategies and the interests of our stakeholders, and we

prohibit engaging in any detrimental activities, such as performing services for

a competitor, disclosing confidential information or violating appropriate

business conduct standards. Each executive is held accountable to uphold and

comply with company guidelines, which require the individual to maintain a

discrimination-free workplace, to comply with orders of regulatory bodies, and

to maintain high standards of operating safety and environmental protection.

Unlike many companies, we have no executive perquisites and, with respect

to our United States-based executives, we have no supplemental executive

retirement, non-qualified supplemental defined benefit/contribution, deferred

compensation or split dollar life insurance programs. We have no executive

company cars or executive car allowances nor do we offer or pay for financial

planning services. Additionally, we do not own any corporate aircraft and we do

not pay for executives to fly first class. We are currently below competitive

levels for comparable companies in this area of our compensation package;

however, we have no current plans to change our policy of not offering such

executive benefits or perquisite programs.

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At his request, Mr. Kinder, our Chairman and Chief Executive Officer,

receives $1 of base salary per year. Additionally, Mr. Kinder has requested that

he receive no annual bonus, stock or unit grants, or other compensation. Mr.

Kinder does not have any deferred compensation, supplemental retirement or any

other special benefit, compensation or perquisite arrangement. He wishes to be

rewarded strictly on the basis of stock performance which impacts the value of

his holdings of KMI common stock, KMP common units and KMR shares. Each year Mr.

Kinder reimburses us for his portion of health care premiums and parking

expenses.

Elements of Compensation

As outlined above, our executive compensation program is principally

comprised of the following three elements: a base cash salary; a possible annual

cash bonus; and a possible long-term equity award. With regard to our executive

officers other than our Chief Executive Officer, KMI's and KMR's compensation

committees review and approve annually the financial goals and objectives of

both KMI and us that are relevant to the compensation of our executive officers.

Generally following the regularly scheduled fourth quarter board meetings in

each year, the committees solicit information from other directors, the Chief

Executive Officer and other relevant members of senior management regarding the

performance of our executive officers other than our Chief Executive Officer

during that year. Our Chief Executive Officer makes compensation recommendations

to the committees with respect to our executive officers, other than himself.

The committees obtain the information and the recommendations prior to the

regularly scheduled first quarter board meetings.

Annually, at KMI's and our regularly scheduled first quarter board

meetings, the committees evaluate the performance of our executive officers

other than our Chief Executive Officer and make determinations regarding the

terms of their continued employment and compensation for that year. If the

committees deem it advisable, they may, rather than determine the terms of

continued employment and compensation for executive officers (other than the

Chief Executive Officer), make a recommendation with respect thereto to the

independent members of the board, who make the determination at the first

quarter board meetings. The committees also determine bonuses for the prior year

based on the performance targets set therefore, and set performance targets for

the present year for bonus and other relevant purposes.

If any executive officer of KMI is also an executive officer of KMR or our

General Partner, the committees' compensation determination or recommendation

(i) may be with respect to the aggregate compensation to be received by such

officer from KMI, KMR, and our General Partner that is to be allocated among

them in accordance with procedures approved by the committees, if such aggregate

compensation set by the committee or the board of KMI and that set by the

committee or the board of KMR are the same, or alternatively (ii) may be with

respect to the compensation to be received by such executive officers from KMI,

KMR or our General Partner, as the case may be, in which case such compensation

will not be allocated among KMI, on the one hand, and KMR, our General Partner

and us, on the other. Further, if any executive officer of KMI is also an

executive officer of KMR, the committees may, to the extent they believe

necessary or desirable, exchange information with respect to evaluation and

compensation recommendations with each other. Thereafter, the committees or the

Chief Executive Officer will discuss the committees' evaluation and the

determination as to compensation with the executive officers.

In addition, the compensation committees have the sole authority to retain

(and terminate as necessary) and compensate any compensation consultants,

counsel and other firms of experts to advise them as they determine necessary or

appropriate. The committees have the sole authority to approve any such firm's

fees and other retention terms, and we and KMI, as applicable, will make

adequate provision for the payment of all fees and other compensation, approved

by the committees, to any such firm employed by the committees. The committees

also have sole authority to determine if any compensation consultant is to be

used to assist in the evaluation of director, Chief Executive Officer or senior

executive compensation and will have sole authority to retain and terminate any

such compensation consultant and to approve the consultant's fees and other

retention terms.

Base Salary

This includes base salary, which is paid in cash. All of our executive

officers, with the exception of our Chairman and Chief Executive Officer who

receives $1 of base salary per year as described above, earn a base salary not

to exceed $200,000 per year. Generally, we believe that our executive officers'

base salaries are below

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base salaries for executives in similar positions and with similar

responsibilities at comparable companies of corresponding size and scope.

Possible Annual Cash Bonus (Non-Equity Cash Incentive)

Our possible annual cash bonuses are provided for under KMI's 2005 Annual

Incentive Plan, which became effective January 18, 2005 and which is referred to

in this report as the KMI Annual Incentive Plan. The overall purpose of the KMI

Annual Incentive Plan is to increase our executive officers' and our employees'

personal stake in the continued success of KMI and us by providing them

additional incentives through the possible payment of annual cash bonuses. Under

the plan, annual cash bonuses may be paid to our executive officers and other

employees depending on a variety of factors, including their individual

performance, KMI's financial performance, the financial performance of KMI's

subsidiaries (including us), and safety and environmental goals.

The plan is administered by the compensation committee of KMI's board of

directors, which consists of three or more directors, each of whom qualifies as

an "outside director" for purposes of the Internal Revenue Code. The

compensation committee is authorized to grant awards under the plan, interpret

the plan, adopt rules and regulations for carrying out the plan, and make all

determinations necessary or advisable for the administration of the plan.

All of the employees of KMI and its subsidiaries, including KMGP Services

Company, Inc., are eligible to participate in the plan, except employees who are

included in a unit of employees covered by a collective bargaining agreement

unless such agreement expressly provides for eligibility under the plan.

However, only eligible employees who are selected by the KMI compensation

committee will actually participate in the plan and receive bonuses.

The plan consists of two components: the executive plan component and the

non-executive plan component. Our Chairman and Chief Executive Officer and all

employees who report directly to the Chairman are eligible for the executive

plan component; however, as stated elsewhere in this report, Mr. Richard D.

Kinder, our Chairman and Chief Executive Officer, does not participate under the

plan. As of January 31, 2007, excluding Mr. Richard D. Kinder, 13 of our current

executive officers were eligible to participate in the executive plan component.

All other U.S. eligible employees were eligible for the non-executive plan

component.

The KMI compensation committee determines which of the eligible employees

will be eligible to participate under the executive plan component of the KMI

Annual Incentive Plan for any given year. At or before the start of each

calendar year (or later, to the extent allowed under Internal Revenue Code

regulations), performance objectives for that year are identified. The

performance objectives are based on one or more of the criteria set forth in the

plan. The KMI compensation committee establishes a bonus opportunity for each

executive officer, which is the amount of the bonus the executive officer will

earn if the performance objectives are fully satisfied. The compensation

committee may specify a minimum acceptable level of achievement of each

performance objective below which no bonus is payable with respect to that

objective. The compensation committee may set additional levels above the

minimum (which may also be above the targeted performance objective), with a

formula to determine the percentage of the bonus opportunity to be earned at

each level of achievement above the minimum. Performance at a level above the

targeted performance objective may entitle the executive officer to earn a bonus

in excess of 100% of the bonus opportunity. However, the maximum payout to any

individual under the KMI Annual Incentive Plan for any year is $2.0 million, and

the KMI compensation committee has the discretion to reduce the bonus amount in

any performance period.

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

criteria:

o KMI's earnings per share;

o KMI cash dividends to its stockholders;

o KMI's earnings before interest and taxes or earnings before interest,

taxes and corporate charges, or the earnings before interest and taxes

or earnings before interest, taxes and corporate charges of one of its

subsidiaries or business units;

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o KMI's net income or the net income of one of its subsidiaries or

business units;

o KMI's revenues or the revenues of one of its subsidiaries or business

units;

o KMI's unit revenues minus unit variable costs or the unit revenues

minus unit variable costs of one of its subsidiaries or business

units;

o KMI's return on capital, return on equity, return on assets, or return

on invested capital, or the return on capital, return on equity,

return on assets, or return on invested capital of one of its

subsidiaries or business units;

o KMI's cash flow return on assets or cash flows from operating

activities, or the cash flow return on assets or cash flows from

operating activities of one of its subsidiaries or business units;

o KMI's capital expenditures or the capital expenditures of one of its

subsidiaries or business units;

o KMI's operations and maintenance expense or general and administrative

expense, or the operations and maintenance expense or general and

administrative expense of one of its subsidiaries or business units;

o KMI's debt-equity ratios and key profitability ratios, or the

debt-equity ratios and key profitability ratios of one of its

subsidiaries or business units; or

o KMI's stock price.

The KMI compensation committee set two performance objectives for 2006

under both the executive plan component and the non-executive plan component.

The 2006 performance objectives were $3.28 in cash distributions per common unit

at KMP, and $5.00 in earnings per share at KMI. These targets were the same as

our and KMI's previously disclosed 2006 budget expectations. At the end of 2006,

the KMI compensation committee determined and certified in writing the extent to

which the performance objectives had been attained and the extent to which the

bonus opportunity had been earned under the formula previously established by

the KMI compensation committee. Because payments under the plan for our

executive officers are determined by comparing actual performance to the

performance objectives established by the compensation committee each year for

eligible executive officers chosen to participate for that year, it is not

possible to accurately predict any amounts that will actually be paid under the

executive plan portion of the plan over the life of the plan.

The below table sets forth the bonus opportunities that would have been

payable to our executive officers if the performance objectives established by

the KMI compensation committee for 2006 had been 100% achieved. The KMI

compensation committee may, at its sole discretion, reduce the amount of the

bonus actually paid to any executive officer under the plan from the amount of

any bonus opportunity open to such executive officer.

KMI Annual Incentive Plan

Bonus Opportunities for 2006(1)

<TABLE>

Name and Principal Position Dollar Value

--------------------------- ------------

<S> <C>

Richard D. Kinder, Chairman and Chief Executive Officer............... $ --(2)

Kimberly A. Dang, Vice President and Chief Financial Officer.......... 1,000,000(3)

Jeffrey R. Armstrong, Vice President (President, Terminals)........... 1,000,000(3)

David D. Kinder, Vice President, Corporate Development and Treasurer.. 1,000,000(3)

Steven J. Kean, Executive Vice President and Chief Operating Officer.. 1,500,000(4)

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

Scott E. Parker, Vice President (President, Natural Gas Pipelines).... 1,000,000(3)

C. Park Shaper, Director and President................................ 1,500,000(4)

</TABLE>

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---------------

(1) No stock, stock options, stock appreciation rights, restricted stock or

similar awards are payable under the plan.

(2) Declined to participate.

(3) Under the plan, for 2006, if neither of the targets was met, no bonus

opportunities would have been provided; if one of the targets was met,

$500,000 in bonus opportunities would have been open; if both of the

targets had been exceeded by 10%, $1,500,000 in bonus opportunities would

have been open. The KMI compensation committee may, in its sole discretion,

reduce the award payable to any participant for any reason.

(4) Under the plan, for 2006, if neither of the targets was met, no bonus

opportunities would have been provided; if one of the targets was met,

$750,000 in bonus opportunities would have been open; if both of the

targets had been exceeded by 10%, $2,000,000 in bonus opportunities would

have been open. The KMI compensation committee may, in its sole discretion,

reduce the award payable to any participant for any reason.

In 2006, excluding the impairment charge resulting from KMI entering into a

definitive agreement to sell its Terasen Gas business segment, KMI exceeded its

established target, but we (KMP) did not achieve our established target.

Excluding Mr. Richard D. Kinder, who does not participate in the plan, our top

three executive officers (Messrs. Shaper, Kean and Listengart) voluntarily

elected to take zero bonuses for work done in 2006. The KMI compensation

committee agreed to the executives' request for zero bonuses, but wanted to make

note that it was no reflection on any of the executives' personal performance

for the year. It was also noted and reflected that each of our other executive

officers' bonus was reduced in accordance with past practice and in light of the

making of just one target. Mr. Parker's bonus was paid $500,000 from the plan

according to the plan terms, and $350,000 from outside the plan as a

discretionary bonus.

The plan was established, in part, to enable the portion of an officer's or

other employee's annual bonus based on objective performance criteria to qualify

as "qualified performance-based compensation" under the Internal Revenue Code.

"Qualified performance-based compensation" is deductible by us for tax purposes.

The tax deduction available with respect to compensation paid to executive

officers is limited, unless the compensation qualifies as performance-based

under the Internal Revenue Code. The requirements for performance-based

compensation include the following:

o the compensation must be paid based solely on the attainment of

objective performance measures established by a committee of outside

directors, and

o the plan providing for such compensation must be approved by KMI

stockholders.

The KMI Annual Incentive Plan is a bonus plan that enables the portion of

an officer or employee's annual bonus based on objective performance criteria to

qualify as performance-based. Accordingly, that amount is deductible without

regard to the deduction limit otherwise imposed by the Internal Revenue Code. If

a bonus paid under the plan to an individual is in excess of the bonus

opportunity set by the compensation committee, Section 162(m) of the Internal

Revenue Code could limit the deductibility of the bonus paid. Consequently, the

compensation committee set bonus opportunities under the plan for 2006 for the

executive officers at dollar amounts in excess of that which were expected to

actually be paid under the plan.

KMI's Board of Directors may amend the plan from time to time without KMI

stockholder approval except as required to satisfy the Internal Revenue Code or

any applicable securities exchange rules. Awards may be granted under the plan

for calendar years 2007 through 2009, unless the plan is terminated earlier by

the KMI Board. However, the plan will remain in effect until payment has been

completed with respect to all awards granted under the plan prior to its

termination.

Restricted KMI Stock Awards

This includes grants of restricted KMI stock under KMI's Amended and

Restated 1999 Stock Plan, referred to in this report as the KMI stock plan. The

KMI stock plan allows for grants of restricted KMI stock and non-qualified KMI

stock options. We believe the plan permits us to keep pace with changing

developments in compensation and benefit programs, making us competitive with

those companies that offer incentives to attract and retain employees.

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The purposes of the KMI stock plan are to:

o enable the employees of KMI and the employees of its subsidiaries to

develop a sense of proprietorship and personal involvement in KMI’s

financial success and the financial success of its subsidiaries,

including us; and

o encourage those employees to remain with and devote their best efforts

to KMI’s business and the business of its subsidiaries, including us.

Officers and other employees of KMI and other entities in which they have a

direct or indirect interest are eligible to participate in the plan. KMI’s

compensation committee, which administers the plan, has the sole discretion to

select participants from among eligible persons. Directors who are not employees

are not eligible to participate in the plan. The aggregate number of shares of

KMI common stock which may be issued under the plan with respect to options,

restricted stock and restricted stock units may not exceed 10,500,000, subject

to adjustment for certain transactions affecting the common stock. Lapsed,

forfeited or canceled options, and shares subject to forfeited restricted stock

units, will not count against this limit and can be regranted under the plan.

Options with respect to more than 1,000,000 shares of KMI common stock,

restricted stock with respect to more than 500,000 shares of KMI common stock

and restricted stock units with respect to more than 100,000 shares of KMI

common stock may not be granted to any one employee during any five year period.

The shares issued under the plan may be issued from shares held in treasury or

from authorized but unissued shares.

The KMI stock plan provides for the grant of:

o nonqualified stock options;

o stock appreciation rights in tandem with stock options;

o restricted stock; and

o restricted stock units.

Awards may be granted individually, in combination, or in tandem as

determined by the KMI compensation committee. KMI's Board of Directors may amend

the plan without KMI stockholder approval, unless that approval is required by

applicable law, rules, regulations or stock exchange requirements; however,

KMI's Board of Directors may not amend the plan in such a way that would impair

the rights of a participant under an award without the consent of such

participant, or that would decrease any authority granted to the KMI

compensation committee in contravention of Rule 16b-3 under the Securities

Exchange Act of 1934, as amended. In addition, KMI's Board of Directors may

terminate the plan at any time.

The KMI compensation committee establishes the form and terms of each grant

of restricted stock, and each grant is evidenced by a written agreement. Shares

of restricted stock are subject to "forfeiture restrictions" that restrict the

transferability of the shares and obligate the participant to forfeit and

surrender the shares under certain circumstances, such as termination of

employment. The KMI compensation committee may decide that forfeiture

restrictions on restricted stock will lapse upon the restricted stock holder's

continued employment for a specified period of time, the attainment of one or

more performance targets established by the KMI compensation committee, the

occurrence of any event or the satisfaction of any condition specified by the

KMI compensation committee, or a combination of any of these. The performance

targets may be based on:

o the price of a share of KMI stock or of the equity of one of its

subsidiaries or business units;

o KMI's earnings per share or the earnings per share of one of its

subsidiaries or business units;

o KMI's total stockholder value or the total stockholder value of one of

its subsidiaries or business units;

o KMI's dividends or distributions or the dividends or distributions of

one of its subsidiaries or business units;

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o KMI's revenues or the revenues of one of its subsidiaries or business

units;

o KMI's debt/equity ratio, interest coverage ratio or

indebtedness/earnings before or after interest, taxes, depreciation

and amortization ratio, or such ratios with respect to one of its

subsidiaries or business units;

o KMI's cash coverage ratio or the cash coverage ratio with respect to

one of its subsidiaries or business units;

o KMI's net income (before or after taxes) or the net income (before or

after taxes) of one of its subsidiaries or business units;

o KMI's cash flow or cash flow return on investments or the cash flow or

cash flow return on investments of one of its subsidiaries or business

units;

o KMI's earnings before or after interest, taxes, depreciation, and/or

amortization or earnings before or after interest, taxes,

depreciation, and/or amortization of one of its subsidiaries or

business units;

o KMI's economic value added or the economic value added of one of its

subsidiaries or business units;

o KMI's return on stockholders' equity or the return on stockholders'

equity of one of its subsidiaries or business units; or

o the payment of a bonus under the KMI Annual Incentive Plan as a result

of the attainment of performance goals based on one or more of the

criteria set forth above.

Each grant of restricted stock may have different forfeiture restrictions,

in the discretion of the KMI compensation committee. The KMI compensation

committee may, in its sole discretion, prescribe additional terms, conditions or

restrictions relating to restricted stock, including, but not limited to, rules

pertaining to the termination of employment (by retirement, disability, death or

otherwise) of a participant prior to the lapse of the forfeiture restrictions,

and terms related to tax matters.

Unless otherwise provided for in a written agreement, a participant will

have the right to receive dividends with respect to restricted stock, to vote

the stock and to enjoy all other stockholder rights, except that:

o the participant will not be entitled to delivery of the stock

certificate unless and until the forfeiture restrictions have lapsed;

o KMI will retain custody of the stock unless and until the forfeiture

restrictions have lapsed;

o the participant may not sell, transfer, pledge, exchange, hypothecate

or otherwise dispose of the stock unless and until the forfeiture

restrictions have lapsed; and

o a breach by a participant of the terms and conditions established by

the KMI compensation committee pursuant to the restricted stock

agreement will cause a forfeiture of the restricted stock by the

participant.

Unless otherwise provided for in a written agreement, dividends payable

with respect to restricted stock will be paid to a participant in cash on the

day on which the corresponding dividend on shares is paid to KMI stockholders,

or as soon as administratively feasible thereafter, but no later than the

fifteenth day of the third calendar month following the day on which the

corresponding dividend is paid to KMI stockholders. The KMI compensation

committee may, in its sole discretion, decide that a participant's right to

receive dividends on restricted stock is subject to the attainment of one or

more performance targets based on the criteria listed above.

The KMI compensation committee at any time may accelerate the time or

conditions under which the forfeiture restrictions lapse. However, except in the

event of a corporate change (as defined in the plan), the KMI compensation

committee may not take any such action with respect to "covered employees"

(within the meaning of Treasury Regulation ss. 1.162-27(c)(2)) if such

restricted stock has been designed to meet the exception for

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performance-based compensation under Section 162(m) of the Internal Revenue Code

unless the performance targets with respect to the restricted stock have been

attained.

For the year ended December 31, 2006, no restricted stock or options to

purchase shares of KMI were granted to any of our executive officers.

Other Compensation

Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined

contribution 401(k) plan. The plan permits all full-time employees of Kinder

Morgan, Inc. and KMGP Services Company, Inc., including the named executive

officers, to contribute between 1% and 50% of base compensation, on a pre-tax

basis, into participant accounts. In addition to a mandatory contribution equal

to 4% of base compensation per year for most plan participants, our general

partner may make special discretionary contributions. Certain employees'

contributions are based on collective bargaining agreements. The mandatory

contributions are made each pay period on behalf of each eligible employee. All

employer contributions, including discretionary contributions, are in the form

of KMI stock that is immediately convertible into other available investment

vehicles at the employee's discretion. Participants may direct the investment of

their contributions into a variety of investments. Plan assets are held and

distributed pursuant to a trust agreement.

For employees hired on or prior to December 31, 2004, all contributions,

together with earnings thereon, are immediately vested and not subject to

forfeiture. Employer contributions for employees hired on or after January 1,

2005 will vest on the second anniversary of the date of hire. Effective October

1, 2005, for new employees of our Terminals business segment, a tiered employer

contribution schedule was implemented. This tiered schedule provides for

employer contributions of 1% for service less than one year, 2% for service

between one and two years, 3% for service between two and five years, and 4% for

service of five years or more. All employer contributions for employees of our

Terminals business segment hired after October 1, 2005 will vest on the fifth

anniversary of the date of hire.

At its July 2006 meeting, the compensation committee of the KMI board of

directors approved a special contribution of an additional 1% of base pay into

the Savings Plan for each eligible employee. Each eligible employee will receive

an additional 1% company contribution based on eligible base pay each pay period

beginning with the first pay period of August 2006 and continuing through the

last pay period of July 2007. The additional 1% contribution is in the form of

KMI common stock (the same as the current 4% contribution) and does not change

or otherwise impact, the annual 4% contribution that eligible employees

currently receive. It may be converted to any other Savings Plan investment fund

at any time and it will vest according to the same vesting schedule described in

the preceding paragraph. Since this additional 1% company contribution is

discretionary, KMI compensation committee approval will be required annually for

each additional contribution. During the first quarter of 2007, excluding the 1%

additional contribution described above, we will not make any additional

discretionary contributions to individual accounts for 2006.

Additionally, in 2006, an option to make after-tax "Roth" contributions

(Roth 401(k) option) to a separate participant account was added to the Savings

Plan as an additional benefit to all participants. Unlike traditional 401(k)

plans, where participant contributions are made with pre-tax dollars, earnings

grow tax-deferred, and the withdrawals are treated as taxable income, Roth

401(k) contributions are made with after-tax dollars, earnings are tax-free, and

the withdrawals are tax-free if they occur after both (i) the fifth year of

participation in the Roth 401(k) option, and (ii) attainment of age 59 1/2,

death or disability. The employer contribution will still be considered taxable

income at the time of withdrawal.

Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and

KMI, including the named executive officers, are also eligible to participate in

a Cash Balance Retirement Plan. Certain employees continue to accrue benefits

through a career-pay formula, "grandfathered" according to age and years of

service on December 31, 2000, or collective bargaining arrangements. All other

employees accrue benefits through a personal retirement account in the Cash

Balance Retirement Plan. Under the plan, we make contributions on behalf of

participating employees equal to 3% of eligible compensation every pay period.

Interest is credited to the personal retirement accounts at the 30-year U.S.

Treasury bond rate, or an approved substitute, in effect each year. Employees

become

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fully vested in the plan after five years, and they may take a lump sum

distribution upon termination of employment or retirement.

The following table sets forth the estimated actuarial present value of

each named executive officer's accumulated pension benefit as of December 31,

2006, under the provisions of the Kinder Morgan Cash Balance Retirement Plan.

With respect to our executive officers, the benefits were computed using the

same assumptions used for financial statement purposes, assuming current

remuneration levels without any salary projection, and assuming participation

until normal retirement at age sixty-five. These benefits are subject to federal

and state income taxes, where applicable, but are not subject to deduction for

social security or other offset amounts.

<TABLE>

Pension Benefits

Current Present Value

Credited Yrs of Accumulated Contributions

Name Plan Name of Service Benefit(1) During 2006

---- --------- ---------- -------------- -------------

Richard D. Kinder.........Cash Balance 6 $ -- $ --

Kimberly A. Dang..........Cash Balance 5 24,114 6,968

Jeffrey R. Armstrong......Cash Balance 6 40,534 7,726

David D. Kinder...........Cash Balance 6 32,114 7,337

Steven J. Kean............Cash Balance 5 33,957 7,422

Joseph Listengart.........Cash Balance 6 42,885 7,835

Scott E. Parker...........Cash Balance 8 62,385 8,735

C. Park Shaper............Cash Balance 6 42,885 7,835

-----------

</TABLE>

(1) The present values in the Pension Benefits table are based on certain

assumptions-including a 6% discount rate, RP 2000 mortality

(post-retirement only), 5% cash balance interest crediting rate, and lump

sums calculated using a 5% interest rate and IRS mortality. We assumed

benefits would commence at normal retirement date or unreduced retirement

date, if earlier. No death or turnover was assumed prior to retirement

date.

Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard

D. Kinder entered into an employment agreement with KMI pursuant to which he

agreed to serve as its Chairman and Chief Executive Officer. His employment

agreement provides for a term of three years and one year extensions on each

anniversary of October 7th. Mr. Kinder, at his initiative, accepted an annual

salary of $1 to demonstrate his belief in our and KMI's long term viability. Mr.

Kinder continues to accept an annual salary of $1, and he receives no other

compensation. Mr. Kinder's employment agreement is extended annually at the

request of KMI's Board of Directors.

KMI's Board of Directors believes that Mr. Kinder's employment agreement

contains provisions that are beneficial to KMI, its subsidiaries and its

stockholders. For example, with limited exceptions, Mr. Kinder is prevented from

competing in any manner with KMI or any of its subsidiaries, while he is

employed by KMI and for 12 months following the termination of his employment

with KMI. The agreement contains provisions that address termination with and

without cause, termination as a result of change in duties or disability, and

death. At his current compensation level, the maximum amount that would be paid

to Mr. Kinder or his estate in the event of his termination is three times

$750,000, or $2.25 million. This payment would be made if Mr. Kinder were

terminated by KMI without cause or if Mr. Kinder terminated his employment with

KMI as a result of change in duties (as defined in the employment agreement).

There are no employment agreements or change-in-control arrangements with any of

our other executive officers.

Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key

personnel are eligible to receive grants of options to acquire common units. The

total number of common units authorized under the option plan is 500,000. None

of the options granted under the option plan may be "incentive stock options"

under Section 422 of the Internal Revenue Code. If an option expires without

being exercised, the number of common units covered by such option will be

available for a future award. The exercise price for an option may not be less

than the fair market value of a common unit on the date of grant. KMR's

compensation committee administers the option plan, and the plan has a

termination date of March 5, 2008. KMR's compensation committee will determine

the duration and vesting of the options to employees at the time of grant, and

no individual employee may be granted options for more than 20,000 common units

in any year. The option plan also granted to each of our non-employee directors

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<PAGE>

option to purchase 10,000 common units at an exercise price equal to the fair

market value of the common units at the end of the trading day on such date.

For the year ended December 31, 2006, no options to purchase common units

were granted to or exercised by any of our executive officers, and as of

December 31, 2006, none of our executive officers owned unexercised common unit

options. For the year ended December 31, 2006, no options to purchase common

units were granted to our non-employee directors; however, one non-employee

director held and exercised 10,000 common unit options during 2006. As of

December 31, 2006, no options to purchase common units were outstanding under

the plan.

Summary Compensation Table

The following table shows compensation paid for services rendered to us

during fiscal year 2006 by (i) our principal executive officer, (ii) our

principal financial officer, (iii) the three most highly compensated executive

officers serving at fiscal year end, and (iv) our three other highest ranking

executive officers (collectively referred to as the "named executive officers"):

<TABLE>

(1) (2) (3) (4) (5)

Non-Equity Change

Name and Stock Option Incentive Plan in Pension All Other

Principal Position Year Salary Bonus Awards Awards Compensation Value Compensation Total

------------------ ---- -------- -------- ---------- -------- -------------- ---------- ------------ ----------

Richard D. Kinder.......2006 $ 1 $ -- $ -- $ -- $ -- $ -- $ -- $ 1

Director, Chairman and

Chief Executive

Officer

Kimberly A. Dang........2006 200,000 -- 139,296 37,023 270,000 6,968 46,253 699,540

Vice President and

Chief Financial Officer

Jeffrey R. Armstrong....2006 200,000 -- 412,467 -- 450,000 7,726 132,878 1,203,071

Vice President

(President,

Terminals)

Steven J. Kean..........2006 200,000 -- 1,591,192 147,943 -- 7,422 284,919 2,231,476

Executive Vice

President and

Chief Operating Officer

David D. Kinder.........2006 200,000 -- 235,207 63,586 315,000 7,337 164,630 985,760

Vice President,

Corporate Development

and Treasurer

Joseph Listengart.......2006 200,000 -- 721,817 -- -- 7,835 224,753 1,154,405

Vice President,

General Counsel and

Secretary

Scott E. Parker.........2006 200,000 350,000 881,317 29,490 500,000 8,735 164,630 2,134,172

Vice President

(President,

Natural Gas Pipelines)

C. Park Shaper..........2006 200,000 -- 1,134,283 24,952 -- 7,835 348,542 1,715,612

Director and President

</TABLE>

---------------------

(1) None of the restricted KMI stock awards were granted in 2006. Table

amounts only represent the calendar year 2006 expense attributable to

KMI restricted stock awarded in 2003, 2004 and 2005, and these awards

were reflected in compensation tables previously filed by us with the

Securities and Exchange Commission. The restricted shares were awarded

according to the provisions of the KMI Stock Plan, and the computed

value earned equaled the SFAS No. 123R

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<PAGE>

expense accumulated during the 2006 calendar year. For grants of

restricted stock, we take the value of the award at time of grant and

accrue the expense over the vesting period according to SFAS No. 123R.

For grants made July 16, 2003--KMI closing price was $53.80,

twenty-five percent of the shares in each grant vest on the third

anniversary after the date of grant and the remaining seventy-five

percent of the shares in each grant vest on the fifth anniversary

after the date of grant. For grants made July 20, 2004--KMI closing

price was $60.79, fifty percent of the shares vest on the third

anniversary after the date of grant and the remaining fifty percent of

the shares vest on the fifth anniversary after the date of grant. For

grants made July 20, 2005--KMI closing price was $89.48, twenty-five

percent of the shares in each grant vest on the third anniversary

after the date of grant and the remaining seventy-five percent of the

shares in each grant vest on the fifth anniversary after the date of

grant.

(2) None of the options to purchase KMI shares were granted in 2006. Table

amounts only represent the calendar year 2006 expense attributable to

options to purchase KMI shares granted in 2002 and 2003, and these

awards were reflected in compensation tables previously filed by us

with the Securities and Exchange Commission. The options were granted

according to the provisions of the KMI Stock Plan, and the computed

value earned equaled the SFAS No. 123R expense accumulated on unvested

options during the 2006 calendar year. For options granted in

2002--volatility of 0.3912 using a 6 year term, 4.01% five year risk

free interest rate return, and a 0.71% expected annual dividend rate.

For options granted in 2003--volatility of 0.3853 using a 6.25 year

term, 3.37% treasury strip quote at time of grant, and a 2.973%

expected annual dividend rate.

(3) Represents amounts paid according to the provisions of the KMI Annual

Incentive Plan--except in the case of Mr. Parker, where $500,000 was

paid under the plan and $350,000 was paid outside of the plan. Amounts

were earned in 2006 but paid in 2007.

(4) Represents the 2006 change in the actuarial present value of

accumulated defined pension benefit (including unvested benefits)

according to the provisions of KMI's Cash Balance Retirement Plan.

(5) Amounts represent value of contributions to the Kinder Morgan Savings

Plan (a 401(k) plan), value of group-term life insurance exceeding

$50,000, taxable parking subsidy and dividends paid on unvested

restricted stock awards. For each individual excluding Mr. Richard D.

Kinder, amounts include $10,000 representing the value of

contributions to the Kinder Morgan Savings Plan. Amounts representing

the value of dividends paid on unvested restricted stock awards are as

follows: for Ms. Dang $35,875; for Mr. Armstrong $122,500; for Mr.

Kean $273,000; for Mr. David D. Kinder $69,563; for Mr. Listengart

$214,375; for Mr. Parker $154,000; and for Mr. Shaper $336,875.

The following supplemental compensation table shows compensation details on

the value of all non-guaranteed and non-discretionary incentive awards granted

during 2006 to our named executive officers. The table includes grant awards

made during 2006 and discloses estimated future payouts for both equity and

non-equity incentive plans.

Grants of Plan-Based Awards

Estimated Future Payouts Under

Non-Equity Incentive Plan Awards(1)

-----------------------------------

Name Threshold Target Maximum

---- --------- ------ -------

Richard D. Kinder........... $ -- $ -- $ --

Kimberly A. Dang............ 500,000 1,000,000 1,500,000

Jeffrey R. Armstrong........ 500,000 1,000,000 1,500,000

Steven J. Kean.............. 750,000 1,500,000 2,000,000

David D. Kinder............. 500,000 1,000,000 1,500,000

Joseph Listengart........... 500,000 1,000,000 1,500,000

Scott E. Parker............. 500,000 1,000,000 1,500,000

C. Park Shaper.............. 750,000 1,500,000 2,000,000

----------

(1) Represents grants under the KMI Annual Incentive Plan for 2006. See

"Elements of Compensation--Possible Annual Cash Bonus (Non-Equity Cash

Incentive)" for a discussion of these awards.

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<PAGE>

The following tables set forth certain information at December 31, 2006

with respect to all outstanding KMI equity awards granted to our named

executive officers.

<TABLE>

Outstanding KMI Equity Awards at 2006 Year-End

Option Awards Stock Awards

--------------------------------------------------------- ------------------------------------

No. of Shares Underlying

Unexercised Options Option Option No. of Shares Market Value

------------------------------- Exercise Expiration that have of Shares that

Name Exercisable Unexercisable Price Date not vested(1) have not vested(2)

---- ----------- ------------- -------- ------------- ------------- ------------------

Richard D. Kinder.............. -- -- $ -- -- -- $ --

Kimberly A. Dang............... 10,250 -- 56.99 Jan. 16, 2012 8,000 846,000

10,000 -- 39.12 July 17, 2012

4,500 -- 53.80 July 16, 2010

Jeffrey R. Armstrong........... 22,000 -- 53.20 Mar. 30, 2011 30,000 3,172,500

Steven J. Kean................. 12,500 -- 56.99 Jan. 16, 2012 78,000 8,248,500

13,500 -- 39.12 July 12, 2012

10,000 -- 53.80 July 16, 2010

David D. Kinder................ 12,500 -- 49.875 Jan. 17, 2011 15,750 1,665,563

100 -- 49.875 Jan. 17, 2011

8,000 -- 39.12 July 12, 2012

Joseph Listengart.............. 50,000 -- 23.8125 Oct. 8, 2009 52,500 5,551,875

6,300 -- 49.875 Jan. 17, 2011

Scott E. Parker................ 10,000 -- 53.80 July 16, 2010 44,000 4,653,000

C. Park Shaper................. 95,000 -- 24.75 Jan. 20, 2010 82,500 8,724,375

25,000 -- 49.875 Jan. 17, 2011

100,000 -- 56.99 Jan. 16, 2012

</TABLE>

----------------

(1) For Ms. Dang, 2,000 shares vest July 20, 2007, 1,500 shares vest July 20,

2009, and 4,500 shares vest July 20, 2010; for Mr. Armstrong 30,000 shares

vest July 16, 2008; for Mr. Kean 4,000 shares vest July 20, 2007, 17,500

shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and 52,500

shares vest July 20, 2010; for Mr. David D. Kinder 11,250 shares vest July

16, 2008, and 4,500 shares vest July 20, 2010; for Mr. Listengart 52,500

shares vest July 16, 2008; for Mr. Parker 4,000 shares vest July 20, 2007,

9,000 shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and

27,000 shares vest July 20, 2010; and for Mr. Shaper 82,500 shares vest

July 16, 2008. Upon closing of the proposed merger agreement providing for

the acquisition of KMI by investors, including Mr. Richard D. Kinder and

other senior members of KMI management, all restricted stock vesting dates

would be accelerated.

(2) Calculated on the basis of the fair market value of the underlying shares

at December 31, 2006 ($105.75).

The following tables set forth certain information for the fiscal year

ended December 31, 2006 with respect to all outstanding KMI equity awards vested

to our named executive officers during 2006 and all exercises of KMI stock

options during 2006.

<TABLE>

KMI Option Exercises and KMI Stock Vested in 2006

Option Awards Stock Awards

------------------------------------ -----------------------------------

Shares Acquired Value Realized Shares Acquired Value Realized

Name on Exercise on Exercise(1) on Vesting on Vesting(2)

---- --------------- -------------- --------------- -------------

Richard D. Kinder.............. -- $ -- -- $ --

Kimberly A. Dang............... -- -- -- --

Jeffrey R. Armstrong........... 10,000 522,642 11,000 1,098,980

Steven J. Kean................. 11,500 757,165 5,000 483,850

David D. Kinder................ -- -- 4,000 399,193

Joseph Listengart.............. -- -- 20,000 1,991,925

Scott E. Parker................ -- -- 625 60,481

C. Park Shaper................. -- -- 30,000 2,991,925

-------

</TABLE>

(1) Calculated on the basis of the fair market value of the underlying shares

at exercise date, minus the exercise price.

(2) Calculated on the basis of the fair market value of underlying shares at

the vesting date.

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<PAGE>

Director Compensation

Compensation Committee Interlocks and Insider Participation. The

compensation committee of KMR functions as our compensation committee. KMR's

compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L.

Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding the

executive officers of our general partner and its delegate, KMR. Mr. Richard D.

Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive

officers of KMR, participate in the deliberations of the KMR compensation

committee concerning executive officer compensation. None of the members of

KMR's compensation committee is or has been one of our officers or employees,

and none of our executive officers served during 2006 on a board of directors of

another entity which has employed any of the members of KMR's compensation

committee.

Directors Fees. Beginning in 2005, our Common Unit Compensation Plan for

Non-Employee Directors, as discussed following, served as compensation for each

of KMR's three non-employee directors. In addition, directors are reimbursed for

reasonable expenses in connection with board meetings. Directors of KMR who are

also employees of KMI (Messrs. Richard D. Kinder and C. Park Shaper) do not

receive compensation in their capacity as directors.

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for

Non-Employee Directors. On January 18, 2005, KMR's compensation committee

established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation

Plan for Non-Employee Directors. The plan is administered by KMR's compensation

committee and KMR's board has sole discretion to terminate the plan at any time.

The primary purpose of this plan was to promote our interests and the interests

of our unitholders by aligning the compensation of the non-employee members of

the board of directors of KMR with unitholders' interests. Further, since KMR's

success is dependent on its operation and management of our business and our

resulting performance, the plan is expected to align the compensation of the

non-employee members of the board with the interests of KMR's shareholders.

The plan recognizes that the compensation to be paid to each non-employee

director is fixed by the KMR board, generally annually, and that the

compensation is payable in cash. Pursuant to the plan, in lieu of receiving cash

compensation, each non-employee director may elect to receive common units. Each

election will be generally at or around the first board meeting in January of

each calendar year and will be effective for the entire calendar year. The

election for 2006 was made effective January 17, 2006, and the election for 2007

was made effective January 16, 2007. A non-employee director may make a new

election each calendar year. The total number of common units authorized under

this compensation plan is 100,000.

Each annual election will be evidenced by an agreement, the Common Unit

Compensation Agreement, between us and each non-employee director, and this

agreement will contain the terms and conditions of each award. Pursuant to this

agreement, all common units issued under this plan are subject to forfeiture

restrictions that expire six months from the date of issuance. Until the

forfeiture restrictions lapse, common units issued under the plan may not be

sold, assigned, transferred, exchanged, or pledged by a non-employee director.

In the event the director's service as a director of KMR is terminated prior to

the lapse of the forfeiture restriction either for cause, or voluntary

resignation, each director will, for no consideration, forfeit to us all common

units to the extent then subject to the forfeiture restrictions. Common units

with respect to which forfeiture restrictions have lapsed will cease to be

subject to any forfeiture restrictions, and we will provide each director a

certificate representing the units as to which the forfeiture restrictions have

lapsed. In addition, each non-employee director will have the right to receive

distributions with respect to the common units awarded to him under the plan, to

vote such common units and to enjoy all other unitholder rights, including

during the period prior to the lapse of the forfeiture restrictions.

The number of common units to be issued to a non-employee director electing

to receive the cash compensation in the form of common units will equal the

amount of such cash compensation awarded, divided by the closing price of the

common units on the New York Stock Exchange on the day the cash compensation is

awarded (such price, the fair market value), rounded down to the nearest 50

common units. The common units will be issuable as specified in the Common Unit

Compensation Agreement. A non-employee director electing to receive the cash

compensation in the form of common units will receive cash equal to the

difference between (i) the cash compensation awarded to such non-employee

director and (ii) the number of common units to be issued to such non-employee

director multiplied by the fair market value of a common unit. This cash payment

will be payable in four equal installments

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<PAGE>

generally around March 31, June 30, September 30 and December 31 of the calendar

year in which such cash compensation is awarded.

On January 17, 2006, each of KMR's three non-employee directors was awarded

cash compensation of $160,000 for board service during 2006. Effective January

17, 2006, each non-employee director elected to receive cash compensation of

$87,780 in the form of our common units and was issued 1,750 common units

pursuant to the plan and its agreements (based on the $50.16 closing market

price of our common units on January 17, 2006, as reported on the New York Stock

Exchange). The remaining $72,220 cash compensation was paid to each of the

non-employee directors as described above. No other compensation was paid to the

non-employee directors during 2006.

On January 17, 2007, each of KMR's three non-employee directors was awarded

cash compensation of $160,000 for board service during 2007. Effective January

17, 2007, each non-employee director elected to receive certain amounts of cash

compensation in the form of our common units and each was issued common units

pursuant to the plan and its agreements (based on the $48.44 closing market

price of our common units on January 17, 2007, as reported on the New York Stock

Exchange). Mr. Gaylord elected to receive cash compensation of $95,911.20 in the

form of our common units and was issued 1,980 common units; Mr. Waughtal elected

to receive cash compensation of $159,852.00 in the form of our common units and

was issued 3,300 common units; and Mr. Hultquist elected to receive cash

compensation of $96,880.00 in the form of our common units and was issued 2,000

common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord;

$148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid to each

of the non-employee directors as described above, and no other compensation will

be paid to the non-employee directors during 2007.

Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's

compensation committee established our Directors' Unit Appreciation Rights Plan.

Pursuant to this plan, each of KMR's three non-employee directors was eligible

to receive common unit appreciation rights. Upon the exercise of unit

appreciation rights, we will pay, within thirty days of the exercise date, the

participant an amount of cash equal to the excess, if any, of the aggregate fair

market value of the unit appreciation rights exercised as of the exercise date

over the aggregate award price of the rights exercised. The fair market value of

one unit appreciation right as of the exercise date will be equal to the closing

price of one common unit on the New York Stock Exchange on that date. The award

price of one unit appreciation right will be equal to the closing price of one

common unit on the New York Stock Exchange on the date of grant. Proceeds, if

any, from the exercise of a unit appreciation right granted under the plan will

be payable only in cash (that is, no exercise will result in the issuance of

additional common units) and will be evidenced by a unit appreciation rights

agreement.

All unit appreciation rights granted vest on the six-month anniversary of

the date of grant. If a unit appreciation right is not exercised in the ten year

period following the date of grant, the unit appreciation right will expire and

not be exercisable after the end of such period. In addition, if a participant

ceases to serve on the board for any reason prior to the vesting date of a unit

appreciation right, such unit appreciation right will immediately expire on the

date of cessation of service and may not be exercised.

On April 1, 2003, the date of adoption of the plan, each of KMR's three

non-employee directors was granted 7,500 unit appreciation rights. In addition,

10,000 unit appreciation rights were granted to each of KMR's three non-employee

directors on January 21, 2004, at the first meeting of the board in 2004. During

the first board meeting of 2005, the plan was terminated and replaced by the

Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for

Non-Employee Directors; however, all unexercised awards made under the plan

remain outstanding. No unit appreciation rights were exercised during 2006, and

as of December 31, 2006, 52,500 unit appreciation rights had been granted,

vested and remained outstanding.

The following table discloses the compensation earned by each of KMR's

three non-employee directors for board service during 2006. In addition,

directors are reimbursed for reasonable expenses in connection with board

meetings. Directors of KMR who are also employees of KMI do not receive

compensation in their capacity as directors.

124

<PAGE>

Non-Employee Director Compensation for Fiscal Year 2006

<TABLE>

Fees Earned or Common Unit All Other

Name Paid in Cash Awards(1) Compensation(2) Total

---- ------------ --------- --------------- -----

Edward O. Gaylord.......... $72,220 $87,780 $3,418 $163,418

Gary L. Hultquist.......... 72,220 87,780 3,418 163,418

Perry M. Waughtal.......... 72,220 87,780 3,418 163,418

</TABLE>

----------

(1) Represents the value of cash compensation received in the form of our

common units according to the provisions of our Common Unit Compensation

Plan for Non-Employee Directors. Value computed as the number of common

units elected to be received in lieu of cash (1,750 on January 17, 2006)

times the closing price on date of election ($50.16 at January 17, 2006).

(2) For each, represents the value of common unit appreciation rights earned

during 2006 according to the provisions of our Directors' Unit Appreciation

Rights Plan for Non-Employee Directors. For grants of common unit

appreciation rights, compensation cost is determined according to the

provisions of SFAS No. 123R--for each common unit appreciation right, equal

to the increase in value of each common unit over its grant-date fair

value. Value of $600 computed as the number of common unit appreciation

rights increasing in value during 2006 (7,500) times the increase in common

unit closing price from December 31, 2005 to December 31, 2006 ($0.08;

equal to $47.90 at December 31, 2006 less $47.82 at December 31, 2005).

Also for each, includes $2,818 for distributions paid on unvested common

units awarded according to the provisions of our Common Unit Compensation

Plan for Non-Employee Directors.

Compensation Committee Report

Throughout fiscal 2006, the compensation committee of KMR's board of

directors was comprised of three directors, each of which the KMR board of

directors has determined meets the criteria for independence under KMR's

governance guidelines and the New York Stock Exchange rules.

The KMR compensation committee has discussed and reviewed the above

Compensation Discussion and Analysis for fiscal year 2006 with management. Based

on this review and discussion, the KMR compensation committee recommended to its

board of directors, that this Compensation Discussion and Analysis be included

in this annual report on Form 10-K for the fiscal year 2006.

KMR Compensation Committee:

---------------------------

Edward O. Gaylord

Gary L. Hultquist

Perry M. Waughtal

Item 12. Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters.

The following table sets forth information as of January 31, 2007,

regarding (a) the beneficial ownership of (i) our common and Class B units, (ii)

the common stock of KMI, the parent company of our general partner, and (iii)

KMR shares by all directors of our general partner and KMR, its delegate, by

each of the named executive officers identified in Item 11. and by all directors

and executive officers as a group and (b) the beneficial ownership of our

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<PAGE>

common and Class B units or shares of KMR by all persons known by our general

partner to own beneficially at least 5% of our common and Class B units and KMR

shares. Unless otherwise noted, the address of each person below is c/o Kinder

Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas

77002.

<TABLE>

Amount and Nature of Beneficial Ownership(1)

Kinder Morgan

Common Units Class B Units Management Shares KMI Voting Stock

--------------------- ---------------------- --------------------- -------------------

Number Percent Number Percent Number of Percent Number of Percent

of Units(2) of Class Of Units(3) Of Class Shares(4) of Class Shares(5) of Class

----------- -------- ----------- -------- ---------- --------- ---------- ---------

Richard D. Kinder(6)................. 315,979 * -- -- 59,910 * 24,000,000 17.90%

C. Park Shaper(7).................... 4,000 * -- -- 2,913 * 352,070 *

Edward O. Gaylord(8)................. 38,480 * -- -- -- -- 2,000 *

Gary L. Hultquist(9)................. 16,500 * -- -- -- -- 500 --

Perry M. Waughtal(10)................ 44,100 * -- -- 43,243 * 70,030 *

Steven J. Kean(11)................... -- -- -- -- -- -- 124,754 *

Joseph Listengart(12)................ 4,198 * -- -- -- -- 140,368 *

Scott E. Parker(13).................. -- -- -- -- -- -- 55,431 *

Kimberly A. Dang(14)................. 121 * -- -- 412 * 33,915 *

David D. Kinder(15).................. 2,186 * -- -- 1,408 * 42,307 *

Jeffrey R. Armstrong(16)............. 1,093 * -- -- -- * 64,417 *

Directors and Executive Officers

as a group (14 persons)(17)....... 436,657 * -- -- 111,174 * 25,101,200 18.61%

Kinder Morgan, Inc.(18).............. 14,355,735 8.90% 5,313,400 100.00% 9,676,909 15.53% -- --

Kayne Anderson Capital Advisors,

L.P.(19).......................... -- -- -- -- 6,250,520 10.79% -- --

OppenheimerFunds, Inc.(20)........... -- -- -- -- 5,230,737 8.40% -- --

Tortoise Capital Advisors, L.L.C.(21) -- -- -- -- 4,047,052 6.50% -- --

----------

</TABLE>

* Less than 1%.

(1) Except as noted otherwise, all units, KMR shares and KMI shares

involve sole voting power and sole investment power. For KMR, see note

(4). On January 18, 2005, KMR's board of directors initiated a rule

requiring each director to own a minimum of 10,000 common units, KMR

shares, or a combination thereof. If a director does not already own

the minimum number of required securities, the director will have six

years to acquire such securities.

(2) As of January 31, 2007, we had 162,823,583 common units issued and

outstanding.

(3) As of January 31, 2007, we had 5,313,400 Class B units issued and

outstanding.

(4) Represent the limited liability company shares of KMR. As of January

31, 2007, there were 62,301,674 issued and outstanding KMR shares,

including two voting shares owned by our general partner. In all

cases, our i-units will be voted in proportion to the affirmative and

negative votes, abstentions and non-votes of owners of KMR shares.

Through the provisions in our partnership agreement and KMR's limited

liability company agreement, the number of outstanding KMR shares,

including voting shares owned by our general partner, and the number

of our i-units will at all times be equal.

(5) As of January 31, 2007, KMI had a total of 134,188,793 shares of

issued and outstanding voting common stock, which excludes 15,023,351

shares held in treasury.

(6) Includes (a) 7,879 common units owned by Mr. Kinder's spouse, (b)

5,173 KMI shares held by Mr. Kinder's spouse and (c) 250 KMI shares

held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder

disclaims any and all beneficial or pecuniary interest in these units

and shares.

(7) Includes options to purchase 220,000 KMI shares exercisable within 60

days of January 31, 2007, and includes 82,500 shares of restricted KMI

stock.

(8) Includes 1,980 restricted common units.

(9) Includes 2,000 restricted common units.

(10) Includes 3,300 restricted common units.

(11) Includes options to purchase 36,000 KMI shares exercisable within 60

days of January 31, 2007, and 78,000 shares of restricted KMI stock.

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(12) Includes options to purchase 56,300 KMI shares exercisable within 60

days of January 31, 2007, and includes 52,500 shares of restricted KMI

stock.

(13) Includes options to purchase 10,000 KMI shares exercisable within 60

days of January 31, 2007, and includes 44,000 shares of restricted KMI

stock.

(14) Includes options to purchase 24,750 KMI shares exercisable within 60

days of January 31, 2007, and includes 8,000 shares of restricted KMI

stock.

(15) Includes 1,211 common units owned by Mr. Kinder's spouse, 240 KMR

shares purchased in November 2004 for Mr. Kinder's son (and nominal

share distributions thereon), options to purchase 20,600 KMI shares

exercisable within 60 days of January 31, 2007, and includes 15,750

shares of restricted KMI stock. Mr. Kinder's son holds 250 shares of

KMI stock, which shares are not included in the number of shares Mr.

Kinder beneficially owns. Mr. Kinder disclaims any and all beneficial

ownership in the KMP common units owned by his wife, and the KMR

shares and the KMI stock owned by his sons.

(16) Includes options to purchase 22,000 KMI shares exercisable within 60

days of January 31, 2007, and includes 30,000 shares of restricted KMI

stock.

(17) Includes options to purchase 458,050 KMI shares exercisable within 60

days of January 31, 2007, and includes 7,280 restricted common units

and 400,750 shares of restricted KMI stock.

(18) Includes common units owned by KMI and its consolidated subsidiaries,

including 1,724,000 common units owned by Kinder Morgan G.P., Inc.

(19) As reported on the Schedule 13G/A filed February 5, 2007 by Kayne

Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson

Capital Advisors, L.P. reported that in regard to KMR shares, it had

sole voting power over 0 shares, shared voting power over 6,978,859

shares, sole disposition power over 0 shares and shared disposition

power over 6,978,859 shares. Mr. Kayne reports that in regard to KMR

shares, he had sole voting power over 1,060 shares, shared voting

power over 6,978,859 shares, sole disposition power over 1,060 shares

and shared disposition power over 6,978,859 shares. Kayne Anderson

Capital Advisors, L.P.'s and Richard A. Kayne's address is 1800 Avenue

of the Stars, Second Floor, Los Angeles, California 90067.

(20) As reported on the Schedule 13G/A filed February 6, 2007 by

OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund.

OppenheimerFunds, Inc. reported that in regard to KMR shares, it had

sole voting power over 0 shares, shared voting power over 5,230,737

shares, sole disposition power over 0 shares and shared disposition

power over 5,230,737 shares. Of those 5,230,737 KMR shares,

Oppenheimer Capital Income Fund had sole voting power over 0 shares,

shared voting power over 3,657,500 shares, sole disposition power over

0 shares and shared disposition power over 3,657,500 shares.

OppenheimerFunds, Inc.'s address is Two World Financial Center, 225

Liberty Street, 11th Floor, New York, New York 10281, and Oppenheimer

Capital Income Fund's address is 6803 South Tucson Way, Centennial,

Colorado 80112.

(21) As reported on the Schedule 13G/A filed February 13, 2007 by Tortoise

Capital Advisors, L.L.C. Tortoise Capital Advisors, L.L.C. reported

that in regard to KMR shares, it had sole voting power over 0 shares,

shared voting power over 3,960,233 shares, sole disposition power over

0 shares and shared disposition power over 4,047,052 shares. Tortoise

Capital Advisors, L.L.C.'s address is 10801 Mastin Blvd., Suite 222,

Overland Park, Kansas 66210.

Equity Compensation Plan Information

The following table sets forth information regarding our equity

compensation plans as of December 31, 2006. Specifically, the table provides

information regarding our Common Unit Option Plan and our Common Unit

Compensation Plan for Non-Employee Directors, both described in Item 11,

"Executive Compensation."

127

<PAGE>

<TABLE>

Number of securities Weighted average Number of securities

to be issued upon exercise exercise price remaining available for

of outstanding options, of outstanding options, future issuance under equity

warrants and rights warrants and rights compensation plans

Plan category (a) (b) (c)

----------------------------------- --------------------------- ----------------------- ----------------------------

Equity compensation plans

approved by security holders - - -

Equity compensation plans

not approved by security holders - - 149,100

-------

Total - - 149,100

=======

</TABLE>

Item 13. Certain Relationships and Related Transactions, and Director

Independence.

For information regarding related transactions, see Note 12 of the notes to

our consolidated financial statements included elsewhere in this report.

Except for transactions through the retail division of KMI, employees must

obtain authorization from the appropriate business unit president of the

relevant company or head of corporate function; and directors, business unit

presidents, executive officers and heads of corporate functions must obtain

authorization from the non-interested members of the audit committee of the

applicable board of directors for any business relationship or proposed business

transaction in which they or an immediate family member has a direct or indirect

interest, or from which they or an immediate family member may derive a personal

benefit (a "related party transaction"). The maximum dollar amount of related

party transactions that may be approved as described above in this paragraph in

any calendar year will be $1.0 million. Any related party transactions that

would bring the total value of such transactions to greater than $1.0 million

will be referred to the audit committee of the appropriate board of directors

for approval or to determine the procedure for approval.

Director Independence

Our limited partnership agreement provides for us to have a general partner

rather than a board of directors. Pursuant to a delegation of control agreement,

our general partner delegated to KMR, to the fullest extent permitted under

Delaware law and our partnership agreement, all of its power and authority to

manage and control our business and affairs, except that KMR cannot take certain

specified actions without the approval of our general partner. Through the

operation of that agreement and our partnership agreement, KMR manages and

controls our business and affairs, and the board of directors of KMR performs

the functions of and acts as our board of directors. Similarly, the standing

committees of KMR's board of directors function as standing committees of our

board. KMR's board of directors is comprised of the same persons who comprise

our general partner's board of directors. References in this report to the board

mean KMR's board, acting as our board of directors, and references to committees

mean KMR's committees, acting as committees of our board of directors.

The board has adopted governance guidelines for the board and charters for

the audit committee, nominating and governance committee and compensation

committee. The governance guidelines and the rules of the New York Stock

Exchange require that a majority of the directors be independent, as described

in those guidelines, the committee charters and rules, respectively. Copies of

the guidelines and committee charters are available on our internet website at

www.kindermorgan.com. To assist in making determinations of independence, the

board has determined that the following categories of relationships are not

material relationships that would cause the affected director not to be

independent:

o If the director was an employee, or had an immediate family member who

was an executive officer, of KMR or us or any of its or our

affiliates, but the employment relationship ended more than three

years prior to the date of determination (or, in the case of

employment of a director as an interim chairman, interim chief

executive officer or interim executive officer, such employment

relationship ended by the date of determination);

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<PAGE>

o If during any twelve month period within the three years prior to the

determination the director received no more than, and has no immediate

family member that received more than, $100,000 in direct compensation

from us or our affiliates, other than (i) director and committee fees

and pension or other forms of deferred compensation for prior service

(provided such compensation is not contingent in any way on continued

service), (ii) compensation received by a director for former service

as an interim chairman, interim chief executive officer or interim

executive officer, and (iii) compensation received by an immediate

family member for service as an employee (other than an executive

officer);

o If the director is at the date of determination a current employee, or

has an immediate family member that is at the date of determination a

current executive officer, of another company that has made payments

to, or received payments from, us and our affiliates for property or

services in an amount which, in each of the three fiscal years prior

to the date of determination, was less than the greater of $1.0

million or 2% of such other company's annual consolidated gross

revenues. Contributions to tax-exempt organizations are not considered

payments for purposes of this determination;

o If the director is also a director, but is not an employee or

executive officer, of our general partner or another affiliate or

affiliates of KMR or us, so long as such director is otherwise

independent; and

o If the director beneficially owns less than 10% of each class of

voting securities of us, our general partner, KMR or Kinder Morgan,

Inc.

The board has affirmatively determined that Messrs. Gaylord, Hultquist and

Waughtal, who constitute a majority of the directors, are independent as

described in our governance guidelines and the New York Stock Exchange rules.

Each of them meets the standards above and has no other relationship with us. In

conjunction with all regular quarterly and certain special board meetings, these

three non-management directors also meet in executive session without members of

management. In January 2007, Mr. Waughtal was elected for a one year term to

serve as lead director to develop the agendas for and preside at these executive

sessions of independent directors.

The governance guidelines and our audit committee charter, as well as the

rules of the New York Stock Exchange and the Securities and Exchange Commission,

require that members of the audit committee satisfy independence requirements in

addition to those above. The board has determined that all of the members of the

audit committee are independent as described under the relevant standards.

Item 14. Principal Accounting Fees and Services

The following sets forth fees billed for the audit and other services

provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31,

2006 and 2005 (in dollars):

Year Ended December 31,

---------------------------

2006 2005

------------ ------------

Audit fees(1).................$ 2,038,215 $ 2,085,800

Audit-Related fees(2)......... -- 34,000

Tax fees(3)................... 1,470,466 1,479,344

------------ ------------

Total.......................$ 3,508,681 $ 3,599,144

============ ============

----------

(1) Includes fees for integrated audit of annual financial statements and

internal control over financial reporting, reviews of the related quarterly

financial statements, and reviews of documents filed with the Securities

and Exchange Commission.

(2) Includes fees for assurance and related services that are reasonably

related to the performance of the audit or review of our financial

statements. 2005 amount represents fees for audit related services

associated with Plantation Pipe Line Company. We account for our investment

in Plantation under the equity method of accounting.

(3) For 2006 and 2005, amounts include fees of $1,356,399 and $1,355,194,

respectively, billed for professional services rendered for tax processing

and preparation of Forms K-1 for our unitholders. Amounts also include fees

of $114,067 and $124,150, respectively, billed for professional services

rendered for tax return review services and for general state, local and

foreign tax compliance and consulting services.

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All services rendered by PricewaterhouseCoopers LLP are permissible under

applicable laws and regulations, and were pre-approved by the audit committee of

KMR and our general partner. Pursuant to the charter of the audit committee of

KMR, the delegate of our general partner, the committee's primary purposes

include the following:

o to select, appoint, engage, oversee, retain, evaluate and terminate

our external auditors;

o to pre-approve all audit and non-audit services, including tax

services, to be provided, consistent with all applicable laws, to us

by our external auditors; and

o to establish the fees and other compensation to be paid to our

external auditors.

The audit committee has reviewed the external auditors' fees for audit and

non audit services for fiscal year 2006. The audit committee considered whether

such non audit services are compatible with maintaining the external auditors'

independence and has concluded that they are compatible at this time.

Furthermore, the audit committee will review the external auditors'

proposed audit scope and approach as well as the performance of the external

auditors. It also has direct responsibility for and sole authority to resolve

any disagreements between our management and our external auditors regarding

financial reporting, will regularly review with the external auditors any

problems or difficulties the auditors encountered in the course of their audit

work, and will, at least annually, use its reasonable efforts to obtain and

review a report from the external auditors addressing the following (among other

items):

o the auditors' internal quality-control procedures;

o any material issues raised by the most recent internal quality-control

review, or peer review, of the external auditors;

o the independence of the external auditors; and

o the aggregate fees billed by our external auditors for each of the

previous two fiscal years.

130

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

See "Index to Financial Statements" set forth on page 134.

(a)(3) Exhibits

*3.1 -- Third Amended and Restated Agreement of Limited Partnership of

Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder

Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the

quarter ended June 30, 2001, filed on August 9, 2001).

*3.2 -- Amendment No. 1 dated November 19, 2004 to Third Amended and

Restated Agreement of Limited Partnership of Kinder Morgan Energy

Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy

Partners, L.P. Form 8-K, filed November 22, 2004).

*3.3 -- Amendment No. 2 to Third Amended and Restated Agreement of Limited

Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit

99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed May 5,

2005).

*4.1 -- Specimen Certificate evidencing Common Units representing Limited

Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder

Morgan Energy Partners, L.P. Registration Statement on Form S-4, File

No. 333-44519, filed on February 4, 1998).

*4.2 -- Indenture dated as of January 29, 1999 among Kinder Morgan Energy

Partners, L.P., the guarantors listed on the signature page thereto

and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior

Debt Securities (filed as Exhibit 4.1 to the Partnership's Current

Report on Form 8-K filed February 16, 1999, File No. 1-11234 (the

"February 16, 1999 Form 8-K")).

*4.3 -- First Supplemental Indenture dated as of January 29, 1999 among

Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed

on the signature page thereto and U.S. Trust Company of Texas, N.A.,

as trustee, relating to $250,000,000 of 6.30% Senior Notes due

February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form

8-K (File No. 1-11234)).

*4.4 -- Second Supplemental Indenture dated as of September 30, 1999 among

Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas,

N.A., as trustee, relating to release of subsidiary guarantors under

the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as

Exhibit 4.4 to the Partnership's Form 10-Q (File No. 1-11234) for the

quarter ended September 30, 1999 (the "1999 Third Quarter Form

10-Q")).

*4.5 -- Indenture dated November 8, 2000 between Kinder Morgan Energy

Partners, L.P. and First Union National Bank, as Trustee (filed as

Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001

(File No. 1-11234)).

*4.6 -- Form of 7.50% Notes due November 1, 2010 (contained in the

Indenture filed as Exhibit 4.8 to the Kinder Morgan Energy Partners,

L.P. Form 10-K (File No. 1-11234) for 2001).

*4.7 -- Indenture dated January 2, 2001 between Kinder Morgan Energy

Partners and First Union National Bank, as trustee, relating to Senior

Debt Securities (including form of Senior Debt Securities) (filed as

Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K (File

No. 1-11234) for 2000).

*4.8 -- Indenture dated January 2, 2001 between Kinder Morgan Energy

Partners and First Union National Bank, as trustee, relating to

Subordinated Debt Securities (including form of Subordinated Debt

Securities) (filed as Exhibit 4.12 to Kinder Morgan Energy Partners,

L.P. Form 10-K (File No. 1-11234) for 2000).

*4.9 -- Certificate of Vice President and Chief Financial Officer of Kinder

Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes

due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as

Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No.

1-11234), filed on March 14, 2001).

*4.10 -- Specimen of 6.75% Notes due March 15, 2011 in book-entry form

(filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K

(File No. 1-11234), filed on March 14, 2001).

*4.11 -- Specimen of 7.40% Notes due March 15, 2031 in book-entry form

(filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K

(File No. 1-11234), filed on March 14, 2001).

131

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*4.12 -- Certificate of Vice President and Chief Financial Officer of Kinder

Morgan Energy Partners, L.P. establishing the terms of the 7.125%

Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032

(filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q

(File No. 1-11234) for the quarter ended March 31, 2002, filed on May

10, 2002).

*4.13 -- Specimen of 7.125% Notes due March 15, 2012 in book-entry form

(filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q

(File No. 1-11234) for the quarter ended March 31, 2002, filed on May

10, 2002).

*4.14 -- Specimen of 7.750% Notes due March 15, 2032 in book-entry form

(filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q

(File No. 1-11234) for the quarter ended March 31, 2002, filed on May

10, 2002).

*4.15 -- Indenture dated August 19, 2002 between Kinder Morgan Energy

Partners, L.P. and Wachovia Bank, National Association, as Trustee

(filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P.

Registration Statement on Form S-4 (File No. 333-100346) filed on

October 4, 2002 (the "October 4, 2002 Form S-4")).

*4.16 -- First Supplemental Indenture to Indenture dated August 19, 2002,

dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and

Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2

to the October 4, 2002 Form S-4).

*4.17 -- Form of 5.35% Note and Form of 7.30% Note (contained in the

Indenture filed as Exhibit 4.1 to the October 4, 2002 Form S-4).

*4.18 -- Senior Indenture dated January 31, 2003 between Kinder Morgan

Energy Partners, L.P. and Wachovia Bank, National Association (filed

as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration

Statement on Form S-3 (File No. 333-102961) filed on February 4, 2003

(the "February 4, 2003 Form S-3")).

*4.19 -- Form of Senior Note of Kinder Morgan Energy Partners, L.P.

(included in the Form of Senior Indenture filed as Exhibit 4.2 to the

February 4, 2003 Form S-3).

*4.20 -- Subordinated Indenture dated January 31, 2003 between Kinder Morgan

Energy Partners, L.P. and Wachovia Bank, National Association (filed

as Exhibit 4.4 to the February 4, 2003 Form S-3).

*4.21 -- Form of Subordinated Note of Kinder Morgan Energy Partners, L.P.

(included in the Form of Subordinated Indenture filed as Exhibit 4.4

to the February 4, 2003 Form S-3).

*4.22 -- Certificate of Vice President, Treasurer and Chief Financial

Officer and Vice President, General Counsel and Secretary of Kinder

Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of

Kinder Morgan Energy Partners, L.P. establishing the terms of the

5.00% Notes due December 15, 2013 (filed as Exhibit 4.25 to Kinder

Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).

*4.23 -- Specimen of 5.00% Notes due December 15, 2013 in book-entry form

(filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form

10-K for 2003 filed March 5, 2004).

*4.24 -- Specimen of 5.125% Notes due November 15, 2014 in book-entry form

(filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form

10-K for 2004 filed March 4, 2005).

*4.25 -- Certificate of Executive Vice President and Chief Financial Officer

and Vice President, General Counsel and Secretary of Kinder Morgan

Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder

Morgan Energy Partners, L.P. establishing the terms of the 5.125%

Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan

Energy Partners, L.P. Form 10-K for 2004 filed March 4, 2005).

*4.26 -- Certificate of Vice President, Treasurer and Chief Financial

Officer and Vice President, General Counsel and Secretary of Kinder

Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of

Kinder Morgan Energy Partners, L.P. establishing the terms of the

5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan

Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2005,

filed on May 6, 2005).

*4.27 -- Specimen of 5.80% Notes due March 15, 2035 in book-entry form

(filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q

for the quarter ended March 31, 2005, filed on May 6, 2005).

4.28 -- Certificate of Vice President and Chief Financial Officer of Kinder

Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of

Kinder Morgan Energy Partners, L.P. establishing the terms of the

6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037.

4.29 -- Specimen of 6.00% Senior Notes due 2017 in book-entry form.

4.30 -- Specimen of 6.50% Senior Notes due 2037 in book-entry form.

4.31 -- Certain instruments with respect to long-term debt of Kinder Morgan

Energy Partners, L.P. and its consolidated subsidiaries which relate

to debt that does not exceed 10% of the total assets of Kinder Morgan

Energy Partners, L.P. and its consolidated subsidiaries are omitted

pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R.

sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to

furnish supplementally to the Securities and Exchange Commission a

copy of each such instrument upon request.

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*10.1 -- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed

as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form

10-K, File No. 1-11234).

*10.2 -- Delegation of Control Agreement among Kinder Morgan Management,

LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P.

and its operating partnerships (filed as Exhibit 10.1 to the Kinder

Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30,

2001).

*10.3 -- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation

Rights Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy

Partners, L.P. Form 10-K for 2003 filed March 5, 2004).

*10.4 -- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors'

Unit Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder

Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).

*10.5 -- Resignation and Non-Compete agreement dated July 21, 2004 between

KMGP Services, Inc. and Michael C. Morgan, President of Kinder Morgan,

Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC

(filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form

10-Q for the quarter ended June 30, 2004, filed on August 5, 2004).

*10.6 -- Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan

for Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan

Energy Partners, L.P. Form 8-K filed January 21, 2005).

*10.7 -- Form of Common Unit Compensation Agreement entered into with

Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy

Partners, L.P. Form 8-K filed January 21, 2005).

*10.8 -- Five-Year Credit Agreement dated as of August 5, 2005 among Kinder

Morgan Energy Partners, L.P., the lenders party thereto and Wachovia

Bank, National Association as Administrative Agent (filed as Exhibit

10.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form

8-K, filed on August 11, 2005).

*10.9 -- First Amendment, dated October 28, 2005, to Five-Year Credit

Agreement dated as of August 5, 2005 among Kinder Morgan Energy

Partners, L.P., the lenders party thereto and Wachovia Bank, National

Association as Administrative Agent (filed as Exhibit 10.1 to Kinder

Morgan Energy Partners, L.P.'s Form 10-Q for the quarter ended

September 30, 2006).

*10.10 -- Second Amendment, dated April 13, 2006, to Five-Year Credit

Agreement dated as of August 5, 2005 among Kinder Morgan Energy

Partners, L.P., the lenders party thereto and Wachovia Bank, National

Association as Administrative Agent (filed as Exhibit 10.2 to Kinder

Morgan Energy Partners, L.P.'s Form 10-Q for the quarter ended

September 30, 2006).

*10.11 -- Third Amendment, dated October 6, 2006, to Five-Year Credit

Agreement dated as of August 5, 2005 among Kinder Morgan Energy

Partners, L.P., the lenders party thereto and Wachovia Bank, National

Association as Administrative Agent (filed as Exhibit 10.3 to Kinder

Morgan Energy Partners, L.P.'s Form 10-Q for the quarter ended

September 30, 2006).

11.1 -- Statement re: computation of per share earnings.

12.1 -- Statement re: computation of ratio of earnings to fixed charges.

21.1 -- List of Subsidiaries.

23.1 -- Consent of PricewaterhouseCoopers LLP.

23.2 -- Consent of Netherland, Sewell and Associates, Inc.

31.1 -- Certification by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the

Securities Exchange Act of 1934, as adopted pursuant to Section 302 of

the Sarbanes-Oxley Act of 2002.

31.2 -- Certification by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the

Securities Exchange Act of 1934, as adopted pursuant to Section 302 of

the Sarbanes-Oxley Act of 2002.

32.1 -- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 -- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted

pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

--------------

* Asterisk indicates exhibits incorporated by reference as indicated; all other

exhibits are filed herewith, except as noted otherwise.

133

<Page>

INDEX TO FINANCIAL STATEMENTS

Page

Number

-------

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

Report of Independent Registered Public Accounting Firm.................... 135

Consolidated Statements of Income for the years ended December 31, 2006,

2005, and 2004............................................................. 137

Consolidated Statements of Comprehensive Income for the years ended

December 31, 2006, 2005, and 2004.......................................... 138

Consolidated Balance Sheets as of December 31, 2006 and 2005............... 139

Consolidated Statements of Cash Flows for the years ended December 31,

2006, 2005, and 2004....................................................... 140

Consolidated Statements of Partners' Capital for the years ended

December 31, 2006, 2005, and 2004.......................................... 141

Notes to Consolidated Financial Statements................................. 142

134

<Page>

Report of Independent Registered Public Accounting Firm

To the Partners of

Kinder Morgan Energy Partners, L.P.:

We have completed integrated audits of Kinder Morgan Energy Partners, L.P.'s

consolidated financial statements and of its internal control over financial

reporting as of December 31, 2006, in accordance with the standards of the

Public Company Accounting Oversight Board (United States). Our opinions, based

on our audits, are presented below.

Consolidated Financial statements

In our opinion, the consolidated financial statements listed in the accompanying

index present fairly, in all material respects, the financial position of Kinder

Morgan Energy Partners, L.P. and its subsidiaries (collectively, the

Partnership) at December 31, 2006 and 2005, and the results of their operations

and their cash flows for each of the three years in the period ended December

31, 2006 in conformity with accounting principles generally accepted in the

United States of America. These financial statements are the responsibility of

the Partnership's management. Our responsibility is to express an opinion on

these financial statements based on our audits. We conducted our audits of these

statements in accordance with the standards of the Public Company Accounting

Oversight Board (United States). Those standards require that we plan and

perform the audit to obtain reasonable assurance about whether the financial

statements are free of material misstatement. An audit of financial statements

includes examining, on a test basis, evidence supporting the amounts and

disclosures in the financial statements, assessing the accounting principles

used and significant estimates made by management, and evaluating the overall

financial statement presentation. We believe that our audits provide a

reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management's assessment, included in Management's Report

on Internal Control Over Financial Reporting appearing under Item 9A, that the

Partnership maintained effective internal control over financial reporting as of

December 31, 2006 based on criteria established in Internal Control - Integrated

Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission (COSO), is fairly stated, in all material respects, based on those

criteria. Furthermore, in our opinion, the Partnership maintained, in all

material respects, effective internal control over financial reporting as of

December 31, 2006, based on criteria established in Internal Control -

Integrated Framework issued by the COSO. The Partnership's management is

responsible for maintaining effective internal control over financial reporting

and for its assessment of the effectiveness of internal control over financial

reporting. Our responsibility is to express opinions on management's assessment

and on the effectiveness of the Partnership's internal control over financial

reporting based on our audit. We conducted our audit of internal control over

financial reporting in accordance with the standards of the Public Company

Accounting Oversight Board (United States). Those standards require that we plan

and perform the audit to obtain reasonable assurance about whether effective

internal control over financial reporting was maintained in all material

respects. An audit of internal control over financial reporting includes

obtaining an understanding of internal control over financial reporting,

evaluating management's assessment, testing and evaluating the design and

operating effectiveness of internal control, and performing such other

procedures as we consider necessary in the circumstances. We believe that our

audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed to

provide reasonable assurance regarding the reliability of financial reporting

and the preparation of financial statements for external purposes in accordance

with generally accepted accounting principles. A company's internal control over

financial reporting includes those policies and procedures that (i) pertain to

the maintenance of records that, in reasonable detail, accurately and fairly

reflect the transactions and dispositions of the assets of the company; (ii)

provide reasonable assurance that transactions are recorded as necessary to

permit preparation of financial statements in accordance with generally accepted

accounting principles, and that receipts and expenditures of the company are

being made only in accordance with authorizations of management and directors of

the company; and (iii) provide reasonable

135

<PAGE>

assurance regarding prevention or timely detection of unauthorized acquisition,

use, or disposition of the company's assets that could have a material effect on

the financial statements.

Because of its inherent limitations, internal control over financial reporting

may not prevent or detect misstatements. Also, projections of any evaluation of

effectiveness to future periods are subject to the risk that controls may become

inadequate because of changes in conditions, or that the degree of compliance

with the policies or procedures may deteriorate. As described in Management's

Report on Internal Control Over Financial Reporting, management has excluded:

o the various oil and gas properties acquired from Journey Acquisition -

I, L.P. and Journey 2000, L.P. on April 5, 2006. The acquisition was

made effective March 1, 2006;

o 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 all of the

membership interests in Lomita Rail Terminal LLC;

o all of the membership interests of Transload Services, LLC, acquired

November 20, 2006;

o all of the membership interests of Devco USA L.L.C., acquired December

1, 2006; and

o the refined petroleum products terminal located in Roanoke, Virginia,

acquired from Motiva Enterprises, LLC effective December 15, 2006,

(the "Acquired Businesses"), each acquired in separate transactions, from its

assessment of internal control over financial reporting as of December 31, 2006

because these businesses were acquired by the Partnership in purchase business

combinations during 2006. We have also excluded these Acquired Businesses from

our audit of internal control over financial reporting. These Acquired

Businesses', in the aggregate, constituted 1.2% and 0.4%, respectively, of total

assets and total revenues of the related consolidated financial statement

amounts as of and for the year ended December 31, 2006.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

March 1, 2007

136

<Page>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>

Year Ended December 31,

2006 2005 2004

----------- ----------- -----------

(In thousands except per unit amounts)

Revenues

Natural gas sales....................................... $ 6,039,866 $ 7,198,499 $ 5,803,065

Services................................................ 2,084,119 1,851,699 1,571,504

Product sales and other................................. 830,598 736,930 558,292

----------- ----------- -----------

8,954,583 9,787,128 7,932,861

----------- ----------- -----------

Costs, Expenses and Other

Gas purchases and other costs of sales.................. 5,990,963 7,167,414 5,767,169

Operations and maintenance.............................. 769,514 747,363 499,714

Fuel and power.......................................... 216,222 183,458 151,480

Depreciation, depletion and amortization................ 413,725 349,827 288,626

General and administrative.............................. 219,575 216,706 170,507

Taxes, other than income taxes.......................... 118,756 108,838 81,369

Other expense (income).................................. (30,306) -- --

----------- ----------- -----------

7,698,449 8,773,606 6,958,865

----------- ----------- -----------

Operating Income.......................................... 1,256,134 1,013,522 973,996

Other Income (Expense)

Earnings from equity investments........................ 76,170 91,660 83,190

Amortization of excess cost of equity investments....... (5,664) (5,644) (5,575)

Interest, net........................................... (331,499) (258,861) (192,882)

Other, net.............................................. 11,065 3,273 2,254

Minority Interest......................................... (15,015) (7,262) (9,679)

----------- ----------- -----------

Income Before Income Taxes................................ 991,191 836,688 851,304

Income Taxes.............................................. (19,048) (24,461) (19,726)

----------- ----------- -----------

Net Income................................................ $ 972,143 $ 812,227 $ 831,578

=========== =========== ===========

General Partner's interest in Net Income.................. $ 512,967 $ 477,300 $ 395,092

Limited Partners' interest in Net Income.................. 459,176 334,927 436,486

----------- ----------- -----------

Net Income................................................ $ 972,143 $ 812,227 $ 831,578

=========== =========== ===========

Basic and Diluted Limited Partners' Net Income per Unit... $ 2.04 $ 1.58 $ 2.22

=========== =========== ===========

Weighted average number of units used in computation

of Limited Partners' Net Income per Unit:

Basic..................................................... 224,585 212,197 196,956

=========== =========== ===========

Diluted................................................... 224,914 212,429 197,038

=========== =========== ===========

Per unit cash distribution declared....................... $ 3.26 $ 3.13 $ 2.87

=========== =========== ===========

</TABLE>

The accompanying notes are an integral part of these

consolidated financial statements.

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<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>

Year Ended December 31,

------------------------------------

2006 2005 2004

---------- ---------- ---------

(In thousands)

Net Income........................................... $ 972,143 $ 812,227 $ 831,578

Change in fair value of derivatives used for

hedging purposes................................... (187,525) (1,045,615) (494,212)

Reclassification of change in fair value of

derivatives to net income......................... 428,137 423,983 192,304

Foreign currency translation adjustments............. 722 (699) 375

---------- ---------- ---------

Total other comprehensive income................... 241,334 (622,331) (301,533)

---------- ---------- ---------

Comprehensive Income................................. $1,213,477 $ 189,896 $ 530,045

========== ========== =========

</TABLE>

The accompanying notes are an integral part of these consolidated

financial statements.

138

<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<TABLE>

December 31,

-------------------------

2006 2005

----------- -----------

ASSETS (Dollars in thousands)

Current Assets

Cash and cash equivalents................................ $ 13,985 $ 12,108

Accounts, notes and interest receivable, net

Trade................................................. 840,755 1,011,716

Related parties....................................... 18,802 2,543

Inventories

Products.............................................. 20,419 18,820

Materials and supplies................................ 13,825 13,292

Gas imbalances

Trade................................................. 7,835 18,220

Related parties....................................... 11,640 -

Gas in underground storage............................... 8,373 7,074

Other current assets..................................... 101,111 131,451

----------- -----------

1,036,745 1,215,224

Property, Plant and Equipment, net......................... 9,445,471 8,864,584

Investments................................................ 425,600 419,313

Notes receivable

Trade.................................................... 1,241 1,468

Related parties.......................................... 89,713 109,006

Goodwill................................................... 828,970 798,959

Other intangibles, net..................................... 213,208 217,020

Deferred charges and other assets.......................... 205,446 297,888

----------- -----------

Total Assets............................................... $12,246,394 $11,923,462

LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities

Accounts payable

Cash book overdrafts.................................. $ 46,215 $ 30,408

Trade................................................. 758,294 996,174

Related parties....................................... 2 16,676

Current portion of long-term debt........................ 1,359,069 -

Accrued interest......................................... 82,444 74,886

Accrued taxes............................................ 37,047 23,536

Deferred revenues........................................ 19,972 10,523

Gas imbalances

Trade................................................. 15,849 22,948

Related parties....................................... -- 1,646

Accrued other current liabilities........................ 566,807 632,088

----------- -----------

2,885,699 1,808,885

Long-Term Liabilities and Deferred Credits

Long-term debt

Outstanding........................................... 4,384,332 5,220,887

Market value of interest rate swaps................... 42,630 98,469

----------- -----------

4,426,962 5,319,356

Deferred revenues........................................ 18,786 6,735

Deferred income taxes.................................... 75,541 70,343

Asset retirement obligations............................. 48,880 42,417

Other long-term liabilities and deferred credits......... 718,274 1,019,655

----------- -----------

5,288,443 6,458,506

Commitments and Contingencies (Notes 13 and 16)

Minority Interest.......................................... 50,599 42,331

----------- -----------

Partners' Capital

Common Units (162,816,303 and 157,005,326 units issued and

outstanding as of December 31, 2006 and 2005,

respectively).......................................... 2,743,786 2,680,352

Class B Units (5,313,400 and 5,313,400 units issued and

Outstanding as of December 31, 2006 and 2005,

respectively).......................................... 103,305 109,594

i-Units (62,301,676 and 57,918,373 units issued and

outstanding as of December 31, 2006 and 2005,

respectively).......................................... 1,906,449 1,783,570

General Partner.......................................... 109,667 119,898

Accumulated other comprehensive loss..................... (841,554) (1,079,674)

----------- -----------

4,021,653 3,613,740

Total Liabilities and Partners' Capital.................... $12,246,394 $11,923,462

=========== ===========

</TABLE>

The accompanying notes are an integral part of these consolidated

financial statements.

139

<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>

Year Ended December 31,

---------------------------------------

2006 2005 2004

----------- ----------- -----------

(In thousands)

Cash Flows From Operating Activities

Net income................................................................. $ 972,143 $ 812,227 $ 831,578

Adjustments to reconcile net income to net cash provided by operating

activities:

Depreciation, depletion and amortization................................. 413,725 349,827 288,626

Amortization of excess cost of equity investments........................ 5,664 5,644 5,575

Gains and other non-cash income from the sale of property, plant and

equipment.............................................................. (15,235) (521) 659

Gains from property casualty indemnifications............................ (15,193) -- --

Earnings from equity investments......................................... (76,170) (91,660) (83,190)

Distributions from equity investments...................................... 67,865 63,098 65,248

Changes in components of working capital:

Accounts receivable...................................................... 162,419 (240,751) (172,393)

Other current assets..................................................... 15,430 (14,129) 26,175

Inventories.............................................................. 661 (13,560) (7,353)

Accounts payable......................................................... (267,479) 294,907 222,377

Accrued interest......................................................... 7,558 17,943 4,568

Accrued liabilities...................................................... (10,766) 4,501 (23,050)

Accrued taxes............................................................ 13,823 (2,301) 3,444

FERC rate reparations, refunds and reserve adjustments..................... (19,079) 105,000 --

Other, net................................................................. 2,049 (795) (7,156)

----------- ----------- -----------

Net Cash Provided by Operating Activities.................................... 1,257,415 1,289,430 1,155,108

----------- ----------- -----------

Cash Flows From Investing Activities

Acquisitions of assets..................................................... (397,412) (307,832) (478,830)

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

projects................................................................. (1,058,265) (863,056) (747,262)

Sale of property, plant and equipment, and other net assets net of removal

costs.................................................................... 70,811 9,874 1,069

Property casualty indemnifications......................................... 13,093 -- --

Net proceeds from margin deposits.......................................... 2,298 -- --

Contributions to equity investments........................................ (2,449) (1,168) (7,010)

Natural gas stored underground and natural gas liquids line-fill........... (12,863) (18,735) (19,189)

Other...................................................................... (3,401) (211) 712

----------- ----------- -----------

Net Cash Used in Investing Activities........................................ (1,388,188) (1,181,128) (1,250,510)

----------- ----------- -----------

Cash Flows From Financing Activities

Issuance of debt........................................................... 4,632,562 4,900,936 6,016,670

Payment of debt............................................................ (3,698,749) (4,463,162) (5,657,566)

Repayments from (Loans to) related party................................... 1,097 2,083 (96,271)

Debt issue costs........................................................... (2,032) (6,058) (5,843)

Increase in cash book overdrafts........................................... 15,807 542 29,866

Proceeds from issuance of common units..................................... 248,420 415,574 506,520

Proceeds from issuance of i-units.......................................... -- -- 67,528

Contributions from minority interest....................................... 109,820 7,839 7,956

Distributions to partners:

Common units............................................................. (512,097) (460,620) (389,912)

Class B units............................................................ (17,162) (16,312) (14,931)

General Partner.......................................................... (523,198) (460,869) (376,005)

Minority interest........................................................ (119,025) (12,065) (10,117)

Other, net................................................................. (3,005) (3,866) (5,822)

----------- ----------- -----------

Net Cash Provided by (Used in) Financing Activities.......................... 132,438 (95,978) 72,073

----------- ----------- -----------

Effect of exchange rate changes on cash and cash equivalents................. 212 (216) --

----------- ----------- -----------

Increase (Decrease) in Cash and Cash Equivalents............................. 1,877 12,108 (23,329)

Cash and Cash Equivalents, beginning of period............................... 12,108 -- 23,329

----------- ----------- -----------

Cash and Cash Equivalents, end of period..................................... $ 13,985 $ 12,108 $ --

=========== =========== ===========

Noncash Investing and Financing Activities:

Contribution of net assets to partnership investments...................... $ 17,003 $ -- $ --

Assets acquired by the issuance of units................................... 1,650 49,635 64,050

Assets acquired by the assumption or incurrence of liabilities............. 6,051 76,574 81,403

Supplemental disclosures of cash flow information:

Cash paid during the year for interest (net of capitalized interest)....... 323,709 245,623 186,870

Cash paid (received) during the year for income taxes...................... 7,607 7,345 (752)

</TABLE>

The accompanying notes are an integral part of these consolidated

financial statements.

140

<PAGE>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

<TABLE>

2006 2005 2004

------------------------- ------------------------- -------------------------

Units Amount Units Amount Units Amount

----------- ----------- ----------- ----------- ----------- ----------

(Dollars in thousands)

Common Units:

Beginning Balance..................... 157,005,326 $ 2,680,352 147,537,908 $ 2,438,011 134,729,258 $1,946,116

Net income............................ -- 325,390 -- 237,779 -- 311,237

Units issued as consideration pursuant

to common unit compensation plan for

non-employee directors.............. 5,250 263 5,250 239 -- --

Units issued as consideration in the

acquisition of assets............... 34,627 1,650 1,022,068 49,635 1,400,000 64,050

Units issued for cash................. 5,771,100 248,228 8,440,100 415,308 11,408,650 506,520

Distributions......................... -- (512,097) -- (460,620) -- (389,912)

----------- ----------- ----------- ----------- ----------- ----------

Ending Balance........................ 162,816,303 2,743,786 157,005,326 2,680,352 147,537,908 2,438,011

Class B Units:

Beginning Balance..................... 5,313,400 109,594 5,313,400 117,414 5,313,400 120,582

Net income............................ -- 10,873 -- 8,492 -- 11,763

Distributions......................... -- (17,162) -- (16,312) -- (14,931)

----------- ----------- ----------- ------------ ----------- ----------

Ending Balance........................ 5,313,400 103,305 5,313,400 109,594 5,313,400 117,414

i-Units:

Beginning Balance..................... 57,918,373 1,783,570 54,157,641 1,694,971 48,996,465 1,515,659

Net income............................ -- 122,913 -- 88,656 -- 113,486

Units issued for cash................. -- (34) -- (57) 1,660,664 65,826

Distributions......................... 4,383,303 -- 3,760,732 -- 3,500,512 --

----------- ----------- ----------- ------------ ----------- ----------

Ending Balance........................ 62,301,676 1,906,449 57,918,373 1,783,570 54,157,641 1,694,971

General Partner:

Beginning Balance..................... -- 119,898 -- 103,467 -- 84,380

Net income............................ -- 512,967 -- 477,300 -- 395,092

Distributions......................... -- (523,198) -- (460,869) -- (376,005)

----------- ----------- ----------- ------------ ----------- ----------

Ending Balance........................ -- 109,667 -- 119,898 -- 103,467

Accum. other comprehensive income (loss):

Beginning Balance..................... -- (1,079,674) -- (457,343) -- (155,810)

Change in fair value of derivatives

used for hedging purposes........... -- (187,525) -- (1,045,615) -- (494,212)

Reclassification of change in fair

value of derivatives to net income.. -- 428,137 -- 423,983 -- 192,304

Foreign currency translation adjustments -- 722 -- (699) -- 375

Adj. to initially apply SFAS No. 158

-other post-retirement benefit acctg.

changes -- (3,214) -- -- -- --

----------- ----------- ----------- ----------- ----------- ----------

Ending Balance........................ -- (841,554) -- (1,079,674) -- (457,343)

Total Partners' Capital................. 230,431,379 $ 4,021,653 220,237,099 $ 3,613,740 207,008,949 $3,896,520

=========== =========== =========== =========== =========== ==========

</TABLE>

The accompanying notes are an integral part of

these consolidated financial statements.

141

<Page>

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

General

Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership

formed in August 1992. Unless the context requires otherwise, references to

"we," "us," "our" or the "Partnership" are intended to mean Kinder Morgan Energy

Partners, L.P. and its consolidated subsidiaries.

We own and manage a diversified portfolio of energy transportation and

storage assets and presently conduct our business through four reportable

business segments. These segments and the activities performed to provide

services to our customers and create value for our unitholders are as follows:

o Products Pipelines - transporting, storing and processing refined

petroleum products;

o Natural Gas Pipelines - transporting, storing, selling and processing

natural gas;

o CO2 - producing, transporting and selling carbon dioxide, commonly

called CO2, for use in, and selling crude oil produced from, enhanced

oil recovery operations; and

o Terminals - transloading, storing and delivering a wide variety of

bulk, petroleum, petrochemical and other liquid products at terminal

facilities located across the United States.

For more information on our reportable business segments, see Note 15.

We focus on providing fee-based services to customers, generally avoiding

near-term commodity price risks and taking advantage of the tax benefits of a

limited partnership structure. We trade on the New York Stock Exchange under the

symbol "KMP," and we conduct our operations through the following five operating

limited partnerships:

o Kinder Morgan Operating L.P. "A" (OLP-A);

o Kinder Morgan Operating L.P. "B" (OLP-B);

o Kinder Morgan Operating L.P. "C" (OLP-C);

o Kinder Morgan Operating L.P. "D" (OLP-D); and

o Kinder Morgan CO2 Company (KMCO2).

Combined, the five partnerships are referred to as our operating

partnerships, and we are the 98.9899% limited partner and our general partner

(described following) is the 1.0101% general partner in each. Both we and our

operating partnerships are governed by Amended and Restated Agreements of

Limited Partnership and certain other agreements that are collectively referred

to in this report as the partnership agreements.

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

Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of

Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware

corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,

Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. KMI trades on

the New York Stock Exchange under the symbol "KMI" and is one of the largest

energy transportation, storage and distribution companies in North America. It

operates or owns an interest in, either for itself or on our behalf,

approximately 43,000 miles of pipelines that transport primarily natural gas,

crude oil, petroleum products and carbon dioxide; more than 155

142

<PAGE>

terminals that store transfer and handle products like gasoline and coal; and

provides natural gas distribution service to over 1.1 million customers. At

December 31, 2006, KMI and its consolidated subsidiaries owned, through its

general and limited partner interests, an approximate 14.7% interest in us.

Kinder Morgan Management, LLC

Kinder Morgan Management, LLC, a Delaware limited liability company, was

formed on February 14, 2001. Its shares represent limited liability company

interests and are traded on the New York Stock Exchange under the symbol "KMR."

Kinder Morgan Management, LLC is referred to as "KMR" in this report. Our

general partner owns all of KMR's voting securities and, pursuant to a

delegation of control agreement, our general partner delegated to KMR, to the

fullest extent permitted under Delaware law and our partnership agreement, all

of its power and authority to manage and control our business and affairs,

except that KMR cannot take certain specified actions without the approval of

our general partner. Under the delegation of control agreement, KMR manages and

controls our business and affairs and the business and affairs of our operating

limited partnerships and their subsidiaries. Furthermore, in accordance with its

limited liability company agreement, KMR's activities are limited to being a

limited partner in, and managing and controlling the business and affairs of us,

our operating limited partnerships and their subsidiaries. As of December 31,

2006, KMR owned approximately 27.0% of our outstanding limited partner units

(which are in the form of i-units that are issued only to KMR).

2. Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements include our accounts and those of our

operating partnerships and their majority-owned and controlled subsidiaries. All

significant intercompany items have been eliminated in consolidation. Certain

amounts from prior years have been reclassified to conform to the current

presentation.

Our consolidated financial statements were prepared in accordance with

accounting principles generally accepted in the United States. We believe,

however, that certain accounting policies are of more significance in our

financial statement preparation process than others. Also, certain amounts

included in or affecting our financial statements and related disclosures must

be estimated, requiring us to make certain assumptions with respect to values or

conditions which cannot be known with certainty at the time the financial

statements are prepared. These estimates and assumptions affect the amounts we

report for assets and liabilities, our revenues and expenses during the

reporting period, and our disclosure of contingent assets and liabilities at the

date of our financial statements.

In preparing our consolidated financial statements and related disclosures,

examples of certain areas that require more judgment relative to others include

our use of estimates in determining:

o the economic useful lives of our assets;

o the fair values used to determine possible asset impairment charges;

o reserves for environmental claims, legal fees, transportation rate

cases and other litigation liabilities;

o provisions for uncollectible accounts receivables;

o volumetric receivable (assets) and payable (liabilities) valuations;

o exposures under contractual indemnifications; and

o various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis, utilizing historical

experience, consultation with experts and other methods we consider reasonable

in the particular circumstances. Nevertheless, actual results may differ

significantly from our estimates. Any effects on our business, financial

position or results of operations resulting

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from revisions to these estimates are recorded in the period in which the facts

that give rise to the revision become known.

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with

original maturities of three months or less.

Accounts Receivables

Our policy for determining an appropriate allowance for doubtful accounts

varies according to the type of business being conducted and the customers being

served. An allowance for doubtful accounts is charged to expense monthly,

generally using a percentage of revenue or receivables, based on a historical

analysis of uncollected amounts, adjusted as necessary for changed circumstances

and customer-specific information. When specific receivables are determined to

be uncollectible, the reserve and receivable are relieved. The following tables

show the balance in the allowance for doubtful accounts and activity for the

years ended December 31, 2006, 2005 and 2004.

<TABLE>

Valuation and Qualifying Accounts

(in thousands)

Balance at Additions Additions Balance at

beginning of charged to costs charged to other end of

Allowance for Doubtful Accounts Period and expenses accounts(1) Deductions(2) period

-------------------------------- ------------ ---------------- ------------------ ----------------- -----------

Year ended December 31, 2006..... $6,542 $ 259 $ 285 $ (267) $6,819

Year ended December 31, 2005..... $8,622 $ 203 $ - $(2,283) $6,542

Year ended December 31, 2004..... $8,783 $1,460 $ 431 $(2,052) $8,622

----------

</TABLE>

(1) Amount for 2006 represents the allowance recognized when we acquired Devco

USA L.L.C. ($155) and Transload Services, LLC ($130). Amount for 2004

represents the allowance recognized when we acquired Kinder Morgan River

Terminals LLC and its consolidated subsidiaries ($393) and TransColorado

Gas Transmission Company ($38).

(2) Deductions represent the write-off of receivables.

In addition, the balances of "Accrued other current liabilities" in our

accompanying consolidated balance sheets include amounts related to customer

prepayments of approximately $10.8 million as of December 31, 2006 and $8.2

million as of December 31, 2005.

Inventories

Our inventories of products consist of natural gas liquids, refined

petroleum products, natural gas, carbon dioxide and coal. We report these assets

at the lower of weighted-average cost or market. We report materials and

supplies at the lower of cost or market. The value of natural gas in our

underground storage facilities under the weighted-average cost method was $8.4

million as of December 31, 2006, and $7.1 million as of December 31, 2005. We

also maintain gas in our underground storage facilities on behalf of certain

third parties. We receive a fee from our storage service customers but do not

reflect the value of their gas stored in our facilities in our accompanying

consolidated balance sheets.

Property, Plant and Equipment

We report property, plant and equipment at its acquisition cost. We expense

costs for maintenance and repairs in the period incurred. The cost of property,

plant and equipment sold or retired and the related depreciation are removed

from our balance sheet in the period of sale or disposition. We charge the

original cost of property sold or retired to accumulated depreciation and

amortization, net of salvage and cost of removal. We do not include

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retirement gain or loss in income except in the case of significant retirements

or sales. Gains and losses on minor system sales, excluding land, are recorded

to the appropriate accumulated depreciation reserve. Gains and losses for

operating systems sales and land sales are booked to income or expense accounts

in accordance with regulatory accounting guidelines.

We compute depreciation using the straight-line method based on estimated

economic lives. Generally, we apply composite depreciation rates to functional

groups of property having similar economic characteristics. The rates range from

2.0% to 12.5%, excluding certain short-lived assets such as vehicles.

Depreciation estimates are based on various factors, including age (in the case

of acquired assets), manufacturing specifications, technological advances and

historical data concerning useful lives of similar assets. Uncertainties that

impact these estimates included changes in laws and regulations relating to

restoration and abandonment requirements, economic conditions, and supply and

demand in the area. When assets are put into service, we make estimates with

respect to useful lives (and salvage values where appropriate) that we believe

are reasonable. However, subsequent events could cause us to change our

estimates, thus impacting the future calculation of depreciation and

amortization expense. Historically, adjustments to useful lives have not had a

material impact on our aggregate depreciation levels from year to year.

Our oil and gas producing activities are accounted for under the successful

efforts method of accounting. Under this method costs that are incurred to

acquire leasehold and subsequent development costs are capitalized. Costs that

are associated with the drilling of successful exploration wells are capitalized

if proved reserves are found. Costs associated with the drilling of exploratory

wells that do not find proved reserves, geological and geophysical costs, and

costs of certain non-producing leasehold costs are expensed as incurred. The

capitalized costs of our producing oil and gas properties are depreciated and

depleted by the units-of-production method. Other miscellaneous property, plant

and equipment are depreciated over the estimated useful lives of the asset.

A gain on the sale of property, plant and equipment used in our oil and gas

producing activities is calculated as the difference between the cost of the

asset disposed of, net of depreciation, and the sales proceeds received. A gain

on an asset disposal is recognized in income in the period that the sale is

closed. A loss on the sale of property, plant and equipment is calculated as the

difference between the cost of the asset disposed of, net of depreciation, and

the sales proceeds received or the maket value if the asset is being held for

sale. A loss is recognized when the asset is sold or when the net cost of an

asset held for sale is greater than the market value of the asset.

In addition, we engage in enhanced recovery techniques in which carbon

dioxide is injected into certain producing oil reservoirs. In some cases, the

acquisition cost of the carbon dioxide associated with enhanced recovery is

capitalized as part of our development costs when it is injected. The

acquisition cost associated with pressure maintenance operations for reservoir

management is expensed when it is injected. When carbon dioxide is recovered in

conjunction with oil production, it is extracted and re-injected, and all of the

associated costs are expensed as incurred. Proved developed reserves are used in

computing units of production rates for drilling and development costs, and

total proved reserves are used for depletion of leasehold costs. The

units-of-production rate is determined by field.

We evaluate the impairment of our long-lived assets in accordance with

Statement of Financial Accounting Standards No. 144, "Accounting for the

Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that

long-lived assets that are to be disposed of by sale be measured at the lower of

book value or fair value less the cost to sell. We review for the impairment of

long-lived assets whenever events or changes in circumstances indicate that our

carrying amount of an asset may not be recoverable. We would recognize an

impairment loss when estimated future cash flows expected to result from our use

of the asset and its eventual disposition is less than its carrying amount.

We evaluate our oil and gas producing properties for impairment of value on

a field-by-field basis or, in certain instances, by logical grouping of assets

if there is significant shared infrastructure, using undiscounted future cash

flows based on total proved and risk-adjusted probable and possible reserves.

Oil and gas producing properties deemed to be impaired are written down to their

fair value, as determined by discounted future cash flows based on total proved

and risk-adjusted probable and possible reserves or, if available, comparable

market values. Unproved oil and gas properties that are individually significant

are periodically assessed for impairment of value, and a loss is recognized at

the time of impairment.

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As discussed in "--Inventories" above, we maintain natural gas in

underground storage as part of our inventory. This component of our inventory

represents the portion of gas stored in an underground storage facility

generally known as "working gas," and represents an estimate of the portion of

gas in these facilities available for routine injection and withdrawal to meet

demand. In addition to this working gas, underground gas storage reservoirs

contain injected gas which is not routinely cycled but, instead, serves the

function of maintaining the necessary pressure to allow efficient operation of

the facility. This gas, generally known as "cushion gas," is divided into the

categories of "recoverable cushion gas" and "unrecoverable cushion gas," based

on an engineering analysis of whether the gas can be economically removed from

the storage facility at any point during its life. The portion of the cushion

gas that is determined to be unrecoverable is considered to be a permanent part

of the facility itself (thus, part of our "Property, Plant and Equipment, net"

balance in our accompanying consolidated balance sheets), and this unrecoverable

portion is depreciated over the facility's estimated useful life. The portion of

the cushion gas that is determined to be recoverable is also considered a

component of the facility but is not depreciated because it is expected to

ultimately be recovered and sold.

Equity Method of Accounting

We account for investments greater than 20% in affiliates, which we do not

control, by the equity method of accounting. Under this method, an investment is

carried at our acquisition cost, plus our equity in undistributed earnings or

losses since acquisition, and less distributions received.

Excess of Cost Over Fair Value

We account for our business acquisitions and intangible assets in

accordance with the provisions of SFAS No. 141, "Business Combinations," and

SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires that

all transactions fitting the description of a business combination be accounted

for using the purchase method, which establishes a new basis of accountability

for the acquired business or assets. The Statement also modifies the accounting

for the excess of cost over the fair value of net assets acquired as well as

intangible assets acquired in a business combination. In addition, this

Statement requires disclosure of the primary reasons for a business combination

and the allocation of the purchase price paid to the assets acquired and

liabilities assumed by major balance sheet caption.

SFAS No. 142 requires that goodwill not be amortized, but instead should be

tested, at least on an annual basis, for impairment. Pursuant to this Statement,

goodwill and other intangible assets with indefinite useful lives can not be

amortized until their useful life becomes determinable. Instead, such assets

must be tested for impairment annually or on an interim basis if events or

circumstances indicate that the fair value of the asset has decreased below its

carrying value. We have selected an impairment measurement test date of January

1 of each year and we have determined that our goodwill was not impaired as of

January 1, 2007.

Other intangible assets with definite useful economic lives are to be

amortized over their remaining useful life and reviewed for impairment in

accordance with the provisions of SFAS No. 144, "Accounting for the Impairment

or Disposal of Long-Lived Assets." In addition, SFAS No. 142 requires disclosure

of information about goodwill and other intangible assets in the years

subsequent to their acquisition, including information about the changes in the

carrying amount of goodwill from period to period and the carrying amount of

intangible assets by major intangible asset class.

Our total unamortized excess cost over fair value of net assets in

consolidated affiliates was $829.0 million as of December 31, 2006 and $799.0

million as of December 31, 2005. Such amounts are reported as "Goodwill" on our

accompanying consolidated balance sheets. Our total unamortized excess cost over

underlying fair value of net assets accounted for under the equity method was

$138.2 million as of both December 31, 2006 and December 31, 2005. Pursuant to

SFAS No. 142, this amount, referred to as equity method goodwill, should

continue to be recognized in accordance with Accounting Principles Board Opinion

No. 18, "The Equity Method of Accounting for Investments in Common Stock."

Accordingly, we included this amount within "Investments" on our accompanying

consolidated balance sheets.

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In almost all cases, the price we paid to acquire our share of the net

assets of our equity investees differed from the underlying book value of such

net assets. This differential consists of two pieces. First, an amount related

to the discrepancy between the investee's recognized net assets at book value

and at current fair values (representing the appreciated value in plant and

other net assets), and secondly, to any premium in excess of fair value

(representing equity method goodwill as described above) we paid to acquire the

investment. The first differential, representing the excess of the fair market

value of our investees' plant and other net assets over its underlying book

value at the date of acquisition totaled $177.1 million and $181.7 million as of

December 31, 2006 and 2005, respectively, and similar to our treatment of equity

method goodwill, we included these amounts within "Investments" on our

accompanying consolidated balance sheets. As of December 31, 2006, this excess

investment cost is being amortized over a weighted average life of approximately

31.7 years.

In addition to our annual impairment test of goodwill, we periodically

reevaluate the amount at which we carry the excess of cost over fair value of

net assets accounted for under the equity method, as well as the amortization

period for such assets, to determine whether current events or circumstances

warrant adjustments to our carrying value and/or revised estimates of useful

lives in accordance with APB Opinion No. 18. The impairment test under APB No.

18 considers whether the fair value of the equity investment as a whole, not the

underlying net assets, has declined and whether that decline is other than

temporary. As of December 31, 2006, we believed no such impairment had occurred

and no reduction in estimated useful lives was warranted.

For more information on our acquisitions, see Note 3. For more information

on our investments, see Note 7.

Revenue Recognition

We recognize revenues as services are rendered or goods are delivered and,

if applicable, title has passed. We generally sell natural gas under long-term

agreements, with periodic price adjustments. In some cases, we sell natural gas

under short-term agreements at prevailing market prices. In all cases, we

recognize natural gas sales revenues when the natural gas is sold to a purchaser

at a fixed or determinable price, delivery has occurred and title has

transferred, and collectibility of the revenue is reasonably assured. The

natural gas we market is primarily purchased gas produced by third parties, and

we market this gas to power generators, local distribution companies, industrial

end-users and national marketing companies. We recognize gas gathering and

marketing revenues in the month of delivery based on customer nominations and

generally, our natural gas marketing revenues are recorded gross, not net of

cost of gas sold.

We provide various types of natural gas storage and transportation services

to customers. The natural gas remains the property of these customers at all

times. In many cases (generally described as "firm service"), the customer pays

a two-part rate that includes (i) a fixed fee reserving the right to transport

or store natural gas in our facilities and (ii) a per-unit rate for volumes

actually transported or injected into/withdrawn from storage. The fixed-fee

component of the overall rate is recognized as revenue in the period the service

is provided. The per-unit charge is recognized as revenue when the volumes are

delivered to the customers' agreed upon delivery point, or when the volumes are

injected into/withdrawn from our storage facilities. In other cases (generally

described as "interruptible service"), there is no fixed fee associated with the

services because the customer accepts the possibility that service may be

interrupted at our discretion in order to serve customers who have purchased

firm service. In the case of interruptible service, revenue is recognized in the

same manner utilized for the per-unit rate for volumes actually transported

under firm service agreements.

We provide crude oil transportation services and refined petroleum products

transportation and storage services to customers. Revenues are recorded when

products are delivered and services have been provided, and adjusted according

to terms prescribed by the toll settlements with shippers and approved by

regulatory authorities.

We recognize bulk terminal transfer service revenues based on volumes

loaded and unloaded. We recognize liquids terminal tank rental revenue ratably

over the contract period. We recognize liquids terminal throughput revenue based

on volumes received and volumes delivered. Liquids terminal minimum take-or-pay

revenue is recognized at the end of the contract year or contract term depending

on the terms of the contract. We recognize transmix processing revenues based on

volumes processed or sold, and if applicable, when title has passed. We

recognize energy-related product sales revenues based on delivered quantities of

product.

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Revenues from the sale of oil, natural gas liquids and natural gas

production are recorded using the entitlement method. Under the entitlement

method, revenue is recorded when title passes based on our net interest. We

record our entitled share of revenues based on entitled volumes and contracted

sales prices. Since there is a ready market for oil and gas production, we sell

the majority of our products soon after production at various locations, at

which time title and risk of loss pass to the buyer. As a result, we maintain a

minimum amount of product inventory in storage and the differences between

actual production and sales is not significant.

Capitalized Interest

We capitalize interest expense during the construction or upgrade of

qualifying assets. Interest expense capitalized in 2006, 2005 and 2004 was $18.4

million, $9.8 million and $6.4 million, respectively.

Unit-Based Compensation

We account for common unit options granted under our common unit option

plan according to the provisions of SFAS No. 123R (revised 2004), "Share-Based

Payment," which became effective for us January 1, 2006. This Statement amends

SFAS No. 123, "Accounting for Stock-Based Compensation," and requires companies

to expense the value of employee stock options and similar awards. According to

the provisions of SFAS No. 123R, share-based payment awards result in a cost

that will be measured at fair value on the awards' grant date, based on the

estimated number of awards that are expected to vest. Companies will recognize

compensation cost for share-based payment awards as they vest, including the

related tax effects, and compensation cost for awards that vest would not be

reversed if the awards expire without being exercised.

However, we have not granted common unit options or made any other

share-based payment awards since May 2000, and as of December 31, 2005, all

outstanding options to purchase our common units were fully vested. Therefore,

the adoption of this Statement did not have an effect on our consolidated

financial statements due to the fact that we have reached the end of the

requisite service period for any compensation cost resulting from share-based

payments made under our common unit option plan.

Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures that

relate to current operations. We expense expenditures that relate to an existing

condition caused by past operations, which do not contribute to current or

future revenue generation. We do not discount environmental liabilities to a net

present value, and we record environmental liabilities when environmental

assessments and/or remedial efforts are probable and we can reasonably estimate

the costs. Generally, our recording of these accruals coincides with our

completion of a feasibility study or our commitment to a formal plan of action.

We recognize receivables for anticipated associated insurance recoveries when

such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims

that could impact our assets or operations, and 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. Often, as the

remediation evaluation and effort progresses, additional information is

obtained, requiring revisions to estimated costs. These revisions are reflected

in our income in the period in which they are reasonably determinable.

In 2006, we made quarterly adjustments to our environmental liabilities to

reflect changes in previous estimates. In making these liability estimations, we

considered the material effect of environmental compliance, pending legal

actions against us, and potential third-party liability claims. As a result, in

2006, we recorded a combined $35.4 million increase in environmental expense

associated with environmental liability adjustments. We recorded a $32.4 million

increase in expense within "Operations and maintenance," a $4.9 million increase

in expense within "Earnings from equity investments," and a $1.9 million

reduction in expense within "Income Taxes" in our accompanying consolidated

statement of income for 2006. The $35.4 million increase in environmental

expense resulted in a $31.8 million increase in expense to our Products

Pipelines business segment, a $2.2 million increase in expense to our Terminals

business segment, a $1.6 million increase in expense to our Natural Gas

Pipelines business segment, and a $0.2 million decrease in expense to our CO2

business segment. The environmental expense adjustment (including our share of

environmental expense associated with liability adjustments recognized by

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Plantation Pipe Line Company) included a $4.1 million increase in our estimated

environmental receivables and reimbursables, a $3.5 million decrease in our

equity investments, a $34.5 million increase in our overall accrued

environmental and related claim liabilities, and a $1.5 million increase in our

accrued expense liabilities.

In December 2005, we recognized a $23.3 million increase in environmental

expense and in our overall accrued environmental and related claim liabilities.

We included this expense within "Operations and maintenance" in our accompanying

consolidated statement of income for 2005. The $23.3 million expense item

resulted from the adjustment of our environmental expenses and accrued

liabilities between our reportable business segments, primarily affecting our

Products Pipelines and our Terminals business segments. The $23.3 million

increase in environmental expense resulted in a $19.6 million increase in

expense to our Products Pipelines business segment, a $3.5 million increase in

expense to our Terminals business segment, a $0.3 million increase in expense to

our CO2 business segment, and a $0.1 million decrease in expense to our Natural

Gas Pipelines business segment.

In December 2004, we recognized a $0.2 million increase in environmental

expenses and an associated $0.1 million increase in deferred income tax expense

resulting from changes to previous estimates. The adjustment included an $18.9

million increase in our estimated environmental receivables and reimbursables

and a $19.1 million increase in our overall accrued environmental and related

claim liabilities. We included the additional $0.2 million environmental expense

within "Other, net" in our accompanying consolidated statement of income for

2004. The $0.3 million expense item, including taxes, is the net impact of a

$30.6 million increase in expense in our Products Pipelines business segment, a

$7.6 million decrease in expense in our Natural Gas Pipelines segment, a $4.1

million decrease in expense in our CO2 segment, and an $18.6 million decrease in

expense in our Terminals business segment. For more information on our

environmental disclosures, see Note 16.

Legal

We are subject to litigation and regulatory proceedings as the result of

our business operations and transactions. We utilize both internal and external

counsel in evaluating our potential exposure to adverse outcomes from orders,

judgments or settlements. 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. For more information on our legal disclosures, see Note 16.

Pensions and Other Post-retirement Benefits

Effective December 31, 2006, we adopted SFAS No. 158, "Employers'

Accounting for Defined Benefit Pension and Other Postretirement Plans, an

amendment of FASB Statement Nos. 87, 88, 106 and 132(R)." This Statement

requires us to fully recognize the overfunded or underfunded status of our SFPP,

L.P. post-retirement benefit plan as an asset or liability in our statement of

financial position. Accordingly, as of December 31, 2006, we recognized a

liability of $5.5 million for the unfunded portion of this post-retirement

benefit plan. We included $0.2 million of this amount within "Accrued other

current liabilities" and the remaining $5.3 million within "Other long-term

liabilities and deferred credits" on our accompanying consolidated balance

sheet. We consider our overall pension and post-retirement benefit liability

exposure to be minimal in relation to the value of our total consolidated assets

and net income. For more information on our pension and post-retirement benefit

disclosures, see Note 10.

Gas Imbalances

We value gas imbalances due to or due from interconnecting pipelines at the

lower of cost or market. Gas imbalances represent the difference between

customer nominations and actual gas receipts from and gas deliveries to our

interconnecting pipelines and shippers under various operational balancing and

shipper imbalance agreements. Natural gas imbalances are either settled in cash

or made up in-kind subject to the pipelines' various tariff provisions.

Minority Interest

As of December 31, 2006, minority interest consisted of the following:

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o the 1.0101% general partner interest in each of our five operating

partnerships;

o the 0.5% special limited partner interest in SFPP, L.P.;

o the 50% interest in Globalplex Partners, a Louisiana joint venture

owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;

o the 33 1/3% interest in International Marine Terminals Partnership, a

Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan

Operating L.P. "C";

o the approximate 31% interest in the Pecos Carbon Dioxide Company, a

Texas general partnership owned approximately 69% and controlled by

Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries;

o the 1% interest in River Terminals Properties, L.P., a Tennessee

partnership owned 99% and controlled by Kinder Morgan River Terminals

LLC; and

o the 25% interest in Guilford County Terminal Company, LLC, a limited

liability company owned 75% and controlled by Kinder Morgan Southeast

Terminals LLC.

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do

not directly pay federal income tax. Our taxable income or loss, which may vary

substantially from the net income or net loss we report in our consolidated

statement of income, is includable in the federal income tax returns of each

partner. The aggregate difference in the basis of our net assets for financial

and tax reporting purposes cannot be readily determined as we do not have access

to information about each partner's tax attributes in us.

Some of our corporate subsidiaries and corporations in which we have an

equity investment do pay federal and state income taxes. Deferred income tax

assets and liabilities for certain operations conducted through corporations are

recognized for temporary differences between the assets and liabilities for

financial reporting and tax purposes. Changes in tax legislation are included in

the relevant computations in the period in which such changes are effective.

Deferred tax assets are reduced by a valuation allowance for the amount of any

tax benefit not expected to be realized.

Foreign Currency Translation

On April 26, 2006, we incorporated Kinder Morgan Canada Terminals ULC, an

Alberta, Canada unlimited liability corporation. Kinder Morgan Canada Terminals

ULC, located in Edmonton, Alberta, is currently constructing a crude oil tank

farm which will have a storage capacity of approximately 2.2 million barrels and

serve as a blending and storage hub for Canadian crude oil. We expect Kinder

Morgan Canada Terminals ULC to begin operations sometime in the third quarter of

2007.

In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly

Global Materials Services LLC. Our acquisition of Kinder Morgan River Terminals

LLC included two wholly-owned subsidiaries which conducted business outside of

the United States. The two foreign subsidiaries are Arrow Terminals, B.V., which

conducts bulk terminal operations in The Netherlands, and Arrow Terminals Canada

Company (NSULC), which conducts bulk terminal operations in Canada.

We account for these three entities in accordance with the provisions of

SFAS No. 52, "Foreign Currency Translation." We translate the assets and

liabilities of each of these two entities to U.S. dollars at year-end exchange

rates. Income and expense items are translated at weighted-average rates of

exchange prevailing during the year and stockholders' equity accounts are

translated by using historical exchange rates. Translation adjustments result

from translating all assets and liabilities at current year-end rates, while

stockholders' equity is translated by using historical and weighted-average

rates. The cumulative translation adjustments balance is reported as a component

of accumulated other comprehensive income/(loss) within Partners' Capital on our

accompanying consolidated balance

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sheet. Due to the limited size of our foreign operations, we do not believe

these foreign currency translations are material to our financial position.

Comprehensive Income

Statement of Financial Accounting Standards No. 130, "Accounting for

Comprehensive Income," requires that enterprises report a total for

comprehensive income. For each of the years ended December 31, 2006, 2005 and

2004, the difference between our net income and our comprehensive income

resulted from unrealized gains or losses on derivatives utilized for energy

commodity price risk hedging purposes and from foreign currency translation

adjustments. For more information on our risk management activities, see Note

14.

Cumulative revenues, expenses, gains and losses that under generally

accepted accounting principals are included within comprehensive income but

excluded from earnings are reported as accumulated other comprehensive

income/(loss) within Partners' Capital in our consolidated balance sheets. In

addition, pursuant to our initial application of SFAS No. 158 "Employers'

Accounting for Defined Benefit Pension and Other Postretirement Plans" on

December 31, 2006, we also recognized prior service credits and actuarial gains

that had not yet been included in net periodic benefit cost as of the end of the

fiscal year as a component of our ending balance of accumulated other

comprehensive income. The following table summarizes changes in the amount of

our "Accumulated other comprehensive loss" in our accompanying consolidated

balance sheets for each of the two years ended December 31, 2005 and 2006 (in

thousands):

<TABLE>

Net unrealized Foreign Other Total

gains/(losses) currency Post-retirement Accumulated other

on cash flow translation benefit comprehensive

hedge derivatives adjustments acctg. changes income/(loss)

----------------- ----------- --------------- -----------------

December 31, 2004.......$ (457,718) $ 375 $ -- $ (457,343)

Change for period....... (621,632) (699) -- (622,331)

----------------- ----------- --------------- -----------------

December 31, 2005....... (1,079,350) (324) -- (1,079,674)

Change for period....... 240,612 722 (3,214) 238,120

----------------- ----------- --------------- -----------------

December 31, 2006.......$ (838,738) $ 398 $ (3,214) $ (841,554)

================= =========== =============== =================

</TABLE>

Net Income Per Unit

We compute Basic Limited Partners' Net Income per Unit by dividing our

limited partners' interest in net income by the weighted average number of units

outstanding during the period. Diluted Limited Partners' Net Income per Unit

reflects the maximum potential dilution that could occur if units whose issuance

depends on the market price of the units at a future date were considered

outstanding, or if, by application of the treasury stock method, options to

issue units were exercised, both of which would result in the issuance of

additional units that would then share in our net income.

Asset Retirement Obligations

We account for asset retirement obligations pursuant to SFAS No. 143,

"Accounting for Asset Retirement Obligations." For more information on our asset

retirement obligations, see Note 4.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of

mitigating our risk resulting from fluctuations in the market price of natural

gas, natural gas liquids and crude oil. In addition, we enter into interest rate

swap agreements for the purpose of hedging the interest rate risk associated

with our debt obligations.

Our derivative contracts are accounted for under SFAS No. 133, "Accounting

for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137,

"Accounting for Derivative Instruments and Hedging Activities - Deferral of the

Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain

Derivative Instruments and Certain Hedging Activities." SFAS No. 133 established

accounting and reporting standards requiring that every derivative contract

(including certain derivative contracts embedded in other contracts) be

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recorded in the balance sheet as either an asset or liability measured at its

fair value. SFAS No. 133 requires that changes in the derivative contract's fair

value be recognized currently in earnings unless specific hedge accounting

criteria are met. If a derivative contract meets those criteria, SFAS No. 133

allows a derivative contract's gains and losses to offset related results on the

hedged item in the income statement, and requires that a company formally

designate a derivative contract as a hedge and document and assess the

effectiveness of derivative contracts associated with transactions that receive

hedge accounting.

Furthermore, if the derivative transaction qualifies for and is designated

as a normal purchase and sale, it is exempted from the fair value accounting

requirements of SFAS No. 133 and is accounted for using traditional accrual

accounting. Our derivative contracts that hedge our commodity price risks

involve our normal business activities, which include the sale of natural gas,

natural gas liquids and crude oil, and these derivative contracts have been

designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133

designates derivative contracts that hedge exposure to variable cash flows of

forecasted transactions as cash flow hedges and the effective portion of the

derivative contract's gain or loss is initially reported as a component of other

comprehensive income (outside earnings) and subsequently reclassified into

earnings when the forecasted transaction affects earnings. The ineffective

portion of the gain or loss is reported in earnings immediately. See Note 14 for

more information on our risk management activities.

Accounting for Regulatory Activities

Our regulated utility operations are accounted for in accordance with the

provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of

Regulation," which prescribes the circumstances in which the application of

generally accepted accounting principles is affected by the economic effects of

regulation. Regulatory assets and liabilities represent probable future revenues

or expenses associated with certain charges and credits that will be recovered

from or refunded to customers through the ratemaking process.

The following regulatory assets and liabilities are reflected within

"Deferred charges and other assets" and "Other long-term liabilities and

deferred credits," respectively, in our accompanying consolidated balance sheets

as of December 31, 2006 and December 31, 2005 (in thousands):

As of December 31,

2006 2005

----------- ---------

Regulated Assets:

Employee benefit costs........... $ 373 $ 328

Fuel Tracker..................... 1,594 --

Deferred regulatory expenses..... 3,238 3,363

----------- ---------

Total regulatory assets.......... 5,205 3,691

Regulated Liabilities:

Deferred income taxes............ 925 1,883

Fuel Tracker..................... -- (1,275)

----------- ---------

Total regulatory liabilities..... 925 608

Net regulatory assets............ $ 4,280 $ 3,083

=========== =========

As of December 31, 2006, all of our regulatory assets and regulatory

liabilities were being recovered from or refunded to customers through rates

over periods ranging from one to five years.

3. Aquisitions, Joint Ventures and Divestitures

During 2006, 2005 and 2004, we completed or made adjustments for the

following significant acquisitions. Each of the acquisitions was accounted for

under the purchase method and the assets acquired and liabilities assumed were

recorded at their estimated fair market values as of the acquisition date. The

preliminary allocation of assets (and any liabilities assumed) may be adjusted

to reflect the final determined amounts during a short period of time following

the acquisition. Although the time that is required to identify and measure the

fair value of the assets acquired and the liabilities assumed in a business

combination will vary with circumstances, generally our allocation period ends

when we no longer are waiting for information that is known to be available or

obtainable. The results of operations from these acquisitions are included in

our consolidated financial statements from the acquisition date.

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Acquisitions and Joint Ventures

<TABLE>

Allocation of Purchase Price

---------------------------------------------------------------

(in millions)

---------------------------------------------------------------

Property Deferred

Purchase Current Plant & Charges Minority

Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest

--- ------ ------------------------------------------ --------- ------- --------- -------- -------- --------

(1) 3/04 ExxonMobil Products Terminals............. $ 50.9 $ - $ 50.9 $ - $ - $ -

(2) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 77.4 22.8 - -

(3) 10/04 Interest in Cochin Pipeline System........ 10.9 - 10.9 - - -

(4) 10/04 Kinder Morgan River Terminals LLC......... 87.9 9.9 43.2 14.6 20.2 -

(5) 11/04 Charter Products Terminals................ 75.2 0.5 70.9 4.9 - (1.1)

(6) 11/04 TransColorado Gas Transmission Company.... 284.5 2.0 280.6 1.9 - -

(7) 12/04 Kinder Morgan Fairless Hills Terminal..... 7.5 0.3 5.9 1.3 - -

(8) 1/05 Claytonville Oil Field Unit .............. 6.5 - 6.5 - - -

(9) 4/05 Texas Petcoke Terminal Region ............ 247.2 - 72.5 161.4 13.3 -

(10) 7/05 Terminal Assets .......................... 36.2 0.5 35.7 - - -

(11) 7/05 General Stevedores, L.P. ................. 10.4 0.6 5.2 0.2 4.4 -

(12) 8/05 North Dayton Natural Gas Storage Facility 109.4 - 71.7 11.7 26.0 -

(13) 8-9/05 Terminal Assets .......................... 4.3 0.4 3.9 - - -

(14) 11/05 Allied Terminal Assets ................... 13.3 0.2 12.6 0.5 - -

(15) 2/06 Entrega Gas Pipeline LLC.................. 244.6 - 244.6 - - -

(16) 4/06 Oil and Gas Properties.................... 63.9 0.2 63.7 - - -

(17) 4/06 Terminal Assets .......................... 61.9 0.5 43.6 - 17.8 -

(18) 11/06 Transload Services, LLC................... 16.8 1.6 6.6 - 8.6 -

(19) 12/06 Devco USA L.L.C........................... 7.3 0.8 - 6.5 - -

(20) 12/06 Roanoke, Virginia Products Terminal....... $ 6.4 $ - $ 6.4 $ - $ - $ -

</TABLE>

(1) ExxonMobil Products Terminals

Effective March 9, 2004, we acquired seven refined petroleum products

terminals in the southeastern United States from ExxonMobil Corporation. Our

purchase price was approximately $50.9 million, consisting of approximately

$48.2 million in cash and $2.7 million in assumed liabilities. The terminals are

located in Collins, Mississippi; Knoxville, Tennessee; Charlotte and Greensboro,

North Carolina; and Richmond, Roanoke and Newington, Virginia. Combined, the

terminals have a total storage capacity of approximately 3.2 million barrels for

gasoline, diesel fuel and jet fuel. As part of the transaction, ExxonMobil

entered into a long-term contract to store products at the terminals. As of our

acquisition date, we expected to invest an additional $1.2 million in the

facilities. The acquisition enhanced our terminal operations in the Southeast

and complemented our December 2003 acquisition of seven products terminals from

ConocoPhillips Company and Phillips Pipe Line Company. The acquired operations

are included as part of our Products Pipelines business segment.

(2) Kinder Morgan Wink Pipeline, L.P.

Effective August 31, 2004, we acquired all of the partnership interests in

Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,

L.P. for a purchase price of approximately $100.3 million, consisting of $89.9

million in cash and the assumption of approximately $10.4 million of

liabilities, including debt of $9.5 million. In September 2004, we paid off the

$9.5 million outstanding debt balance. We renamed the limited partnership Kinder

Morgan Wink Pipeline, L.P., and we have included its results as part of our CO2

business segment. The acquisition included a 450-mile crude oil pipeline system,

consisting of four mainline sections, numerous gathering systems and truck

off-loading stations. The mainline sections, all in Texas, have a total capacity

of 130,000 barrels of crude oil per day (with the use of a drag reducing agent).

As part of the transaction, we entered into a long-term throughput agreement

with Western Refining Company, L.P. to transport crude oil into Western's

120,000 barrel per day refinery in El Paso, Texas. The acquisition allows us to

better manage crude oil deliveries from our oil field interests in West Texas.

Our allocation of the purchase price to assets acquired and liabilities assumed

was based on an appraisal of fair market values, which was completed in the

second quarter of 2005. The $22.8 million of deferred charges and other assets

in the table above represents the fair value of the intangible long-term

throughput agreement.

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(3) Interest in Cochin Pipeline

Effective October 1, 2004, we acquired an additional undivided 5% interest

in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation

for approximately $10.9 million. On November 3, 2000, we acquired from NOVA

Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System

for approximately $120.5 million. On June 20, 2001, we acquired an additional

2.3% ownership interest from Shell Canada Limited for approximately $8.1

million, and effective December 31, 2001, we purchased an additional 10%

ownership interest from NOVA Chemicals Corporation for approximately $29

million. We now own approximately 49.8% of the Cochin Pipeline System. A

subsidiary of BP owns the remaining interest and operates the pipeline. We

record our proportional share of joint venture revenues and expenses and cost of

joint venture assets with respect to the Cochin Pipeline System as part of our

Products Pipelines business segment.

(4) Kinder Morgan River Terminals LLC

Effective October 6, 2004, we acquired Global Materials Services LLC and

its consolidated subsidiaries from Mid-South Terminal Company, L.P. for

approximately $87.9 million, consisting of $31.8 million in cash and $56.1

million of assumed liabilities, including debt of $33.7 million. In the last

half of 2005, we made purchase price adjustments to the acquired assets based on

an appraisal of fair market values and our evaluation of acquired income tax

assets and liabilities.

Global Materials Services LLC, which we renamed Kinder Morgan River

Terminals LLC, operates a network of 21 river terminals and two rail

transloading facilities primarily located along the Mississippi River system.

The network provides loading, storage and unloading points for various bulk

commodity imports and exports. As of our acquisition date, we expected to invest

an additional $9.4 million over the next two years to expand and upgrade the

terminals, which are located in 11 Mid-Continent states. The acquisition further

expanded and diversified our customer base and complemented our existing

terminal facilities located along the lower-Mississippi River system. The

acquired terminals are included in our Terminals business segment.

The $20.2 million of goodwill was assigned to our Terminals business

segment, and the entire amount is expected to be deductible for tax purposes. We

believe this acquisition resulted in the recognition of goodwill primarily due

to the fact that certain advantageous factors and conditions existed that

contributed to the fair value of acquired identifiable net assets and

liabilities exceeding our acquisition price--in the aggregate, these factors

represented goodwill. The $14.6 million of deferred charges and other assets in

the table above includes $11.9 million representing the fair value of intangible

customer relationships, which encompass both the contractual life of customer

contracts plus any future customer relationship value beyond the contract life.

(5) Charter Products Terminals

Effective November 5, 2004, we acquired ownership interests in nine refined

petroleum products terminals in the southeastern United States from Charter

Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2

million, consisting of $72.4 million in cash and $2.8 million of assumed

liabilities. 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. We fully own seven of the terminals and jointly own the remaining two.

The nine facilities have a combined 3.2 million barrels of storage. All of the

terminals are connected to products pipelines owned by either Plantation Pipe

Line Company or Colonial Pipeline Company. The acquisition complemented the

other terminals we own in the Southeast and increased our southeast terminal

storage capacity 76% (to 7.7 million barrels) and terminal throughput capacity

62% (to over 340,000 barrels per day). The acquired terminals are included as

part of our Products Pipelines business segment.

In the fourth quarter of 2005, we made purchase price adjustments that

increased property, plant and equipment $11.2 million, increased investments

$1.0 million, decreased goodwill $13.1 million and increased other intangibles

$0.9 million. The changes were based on an appraisal of fair market values,

which was completed in the fourth quarter of 2005. The $4.9 million of deferred

charges and other assets in the table above includes $0.9 million

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representing the fair value of intangible customer relationships, which

encompass both the contractual life of customer contracts plus any future

customer relationship value beyond the contract life.

(6) TransColorado Gas Transmission Company

Effective November 1, 2004, we acquired all of the partnership interests in

TransColorado Gas Transmission Company from two wholly-owned subsidiaries of

KMI. TransColorado Gas Transmission Company, a Colorado general partnership

referred to in this report as TransColorado, owned assets valued at

approximately $284.5 million. As consideration for TransColorado, we paid to KMI

$211.2 million in cash and approximately $64.0 million in units, consisting of

1,400,000 common units. We also assumed liabilities of approximately $9.3

million. The purchase price for this transaction was determined by the boards of

directors of KMR and our general partner, and KMI based on valuation parameters

used in the acquisition of similar assets. The transaction was approved

unanimously by the independent members of the boards of directors of both KMR

and our general partner, and KMI, with the benefit of advice of independent

legal and financial advisors, including the receipt of fairness opinions from

separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley

& Co. TransColorado owns a 300-mile interstate natural gas pipeline that

originates in the Piceance Basin of western Colorado and runs to the Blanco Hub

in northwest New Mexico. The acquisition expanded our natural gas operations

within the Rocky Mountain region and the acquired operations are included as

part of our Natural Gas Pipelines business segment.

(7) Kinder Morgan Fairless Hills Terminal

Effective December 1, 2004, we acquired substantially all of the assets

used to operate the major port distribution facility located at the Fairless

Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of

approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million

in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless

Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located

along the Delaware River. It is the largest port on the East Coast for the

handling of semi-finished steel slabs, which are used as feedstock by domestic

steel mills. The port operations at Fairless Hills also include the handling of

other types of steel and specialized cargo that caters to the construction

industry and service centers that use steel sheet and plate. In the second

quarter of 2005, after completing a final inventory count, we allocated $0.3

million of our purchase price that was originally allocated to property, plant

and equipment to current assets (materials and supplies-parts inventory). The

terminal acquisition expanded our presence along the Delaware River and

complemented our existing Mid-Atlantic terminal facilities. We include its

operations in our Terminals business segment.

(8) Claytonville Oil Field Unit

Effective January 31, 2005, we acquired an approximate 64.5% gross working

interest in the Claytonville oil field unit located in Fisher County, Texas from

Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in

the Permian Basin of West Texas. Our purchase price was approximately $6.5

million, consisting of $6.2 million in cash and the assumption of $0.3 million

of liabilities. Following our acquisition, we became the operator of the field,

which at the time of acquisition was producing approximately 200 barrels of oil

per day. The acquisition of this ownership interest complemented our existing

carbon dioxide assets in the Permian Basin and we include the acquired

operations as part of our CO2 business segment. Currently, we are performing

technical evaluations to confirm the carbon dioxide enhanced oil recovery

potential and generate definitive plans to develop this potential, if proven to

be economic.

(9) Texas Petcoke Terminal Region

Effective April 29, 2005, we acquired seven bulk terminal operations from

Trans-Global Solutions, Inc. for an aggregate consideration of approximately

$247.2 million, consisting of $186.0 million in cash, $46.2 million in common

units, and an obligation to pay an additional $15 million on April 29, 2007, two

years from closing. We will settle the $15 million liability by issuing

additional common units. 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. We combined the

acquired operations into a new terminal region called the Texas Petcoke region,

as certain of the terminals have contracts in place to provide petroleum coke

handling

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<PAGE>

services for major Texas oil refineries. The acquisition complemented our

existing Gulf Coast terminal facilities and expanded our pre-existing petroleum

coke handling operations. The acquired operations are included as part of our

Terminals business segment.

In the fourth quarter of 2005, we made purchase price adjustments that

increased property, plant and equipment $0.1 million, increased goodwill $1.0

million and decreased other intangibles $1.3 million. The changes were based on

an appraisal of fair market values, which was completed in the fourth quarter of

2005. The $13.3 million of goodwill was assigned to our Terminals business

segment and the entire amount is expected to be deductible for tax purposes. We

believe this acquisition resulted in the recognition of goodwill primarily due

to the fact that certain advantageous factors and conditions existed that

contributed to the fair value of acquired identifiable net assets and

liabilities exceeding our acquisition price--in the aggregate, these factors

represented goodwill. The $161.4 million of deferred charges and other assets in

the table above represents the fair value of intangible customer relationships,

which encompass both the contractual life of customer contracts plus any future

customer relationship value beyond the contract life. In connection with the

transaction, Trans-Global Solutions, Inc. agreed to indemnify Kinder Morgan

G.P., Inc. for any losses relating to our failure to repay $50.9 million of

indebtedness incurred to fund the acquisition, and we agreed to indemnify

Trans-Global Solutions, Inc. for any taxes of Trans-Global Solutions, Inc. that

may arise from the sale of any acquired assets. We have no current intention to

sell any of the assets acquired in this transaction.

(10) July 2005 Terminal Assets

In July 2005, we acquired three terminal facilities in separate

transactions for an aggregate consideration of approximately $36.2 million in

cash. For the three terminals combined, as of the acquisition date, we expected

to invest approximately $14 million subsequent to acquisition in order to

enhance the terminals' operational efficiency. The largest of the transactions

was the purchase of a refined petroleum products terminal in New York Harbor

from ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk

river terminal located in the State of Kentucky, and the third involved a

liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of

all three facilities are included in our Terminals business segment.

The New York Harbor terminal, located on Staten Island and referred to as

the Kinder Morgan Staten Island terminal, complements our existing Northeast

liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At

the time of acquisition, the terminal had storage capacity of 2.3 million

barrels for gasoline, diesel and fuel oil, and we expected to bring several idle

tanks back into service that would add another 550,000 barrels of capacity. In

addition, we planned to rebuild a ship berth with the ability to accommodate

tanker vessels. As part of the transaction, ExxonMobil entered into a long-term

storage capacity agreement with us and has continued to utilize a portion of the

terminal.

The dry-bulk terminal, located along the Ohio River in Hawesville,

Kentucky, primarily handles wood chips and finished paper products. The

acquisition complemented our existing terminal assets located in the Ohio River

Valley and further expanded our wood-chip handling businesses. As part of the

transaction, we assumed a long-term handling agreement with Weyerhauser Company,

an international forest products company, and we planned to expand the terminal

in order to increase utilization and provide storage services for additional

products.

The assets acquired at the liquids/dry-bulk facility in Blytheville,

Arkansas consisted of storage and supporting infrastructure for 40,000 tons of

anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons

of urea. As part of the transaction, we have entered into a long-term agreement

to sublease all of the existing anhydrous ammonia and urea ammonium nitrate

terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two

facilities in the United States that can handle imported fertilizer and provide

shipment west on railcars, and the acquisition of the facility positioned us to

take advantage of the increase in fertilizer imports that has resulted from the

recent decrease in domestic production.

(11) General Stevedores, L.P.

Effective July 31, 2005, we acquired all of the partnership interests in

General Stevedores, L.P. for an aggregate consideration of approximately $10.4

million, consisting of $2.0 million in cash, $3.4 million in common units, and

$5.0 million in assumed liabilities, including debt of $3.0 million. In August

2005, we paid the $3.0 million

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outstanding debt balance, and in 2006, we made our final purchase price

adjustments and the final allocation of our purchase price to assets acquired

and liabilities assumed. The adjustments included minor revisions to acquired

working capital items, and, pursuant to an appraisal of acquired fixed asset and

land values, adjustments to property, plant and equipment, goodwill, and

deferred tax liabilities.

General Stevedores, L.P. owns, operates and leases barge unloading

facilities located along the Houston, Texas ship channel. Its operations

primarily consist of receiving, storing and transferring semi-finished steel

products, including coils, pipe and billets. The acquisition complemented and

further expanded our existing Texas Gulf Coast terminal facilities, and its

operations are included as part of our Terminals business segment. The $4.4

million of goodwill was assigned to our Terminals business segment, and the

entire amount is expected to be deductible for tax purposes. We believe this

acquisition resulted in the recognition of goodwill primarily due to the fact

that certain advantageous factors and conditions existed that contributed to the

fair value of acquired identifiable net assets and liabilities exceeding our

acquisition price--in the aggregate, these factors represented goodwill.

(12) North Dayton Natural Gas Storage Facility

Effective August 1, 2005, we acquired a natural gas storage facility in

Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of

approximately $109.4 million, consisting of $52.9 million in cash and $56.5

million in assumed debt. The facility, referred to as our North Dayton storage

facility, has 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

(cushion) gas. The acquisition complemented our existing Texas intrastate

natural gas pipeline group assets and positioned us to pursue expansions at the

facility that will provide or offer needed services to utilities, the growing

liquefied natural gas industry along the Texas Gulf Coast, and other natural gas

storage users. Additionally, as part of the transaction, we entered into a

long-term storage capacity and transportation agreement with Texas Genco, one of

the largest wholesale electric power generating companies in the United States,

with over 13,000 megawatts of generation capacity. The agreement covers storage

services for approximately 2.0 billion cubic feet of natural gas capacity and

expires on March 1, 2017. The North Dayton storage facility's operations are

included in our Natural Gas Pipelines business segment.

Our allocation of the purchase price to assets acquired and liabilities

assumed was based on an appraisal of fair market values, which was completed in

the fourth quarter of 2005. The $26.0 million of goodwill was assigned to our

Natural Gas Pipelines business segment and the entire amount is expected to be

deductible for tax purposes. We believe our acquisition of the North Dayton

natural gas storage facility resulted in the recognition of goodwill primarily

due to the fact that the favorable location and the favorable association with

our pre-existing assets contributed to the fair value of acquired identifiable

net assets and liabilities exceeding our acquisition price--in the aggregate,

these factors represented goodwill. The $11.7 million of deferred charges and

other assets in the table above represents the fair value of the intangible

long-term natural gas storage capacity and transportation agreement.

(13) August and September 2005 Terminal Assets

In August and September 2005, we acquired certain terminal facilities and

assets, including both real and personal property, in two separate transactions

for an aggregate consideration of approximately $4.3 million in cash. In August

2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from

White Material Handling, Inc., and in September 2005, we spent $2.4 million to

acquire a repair shop and related assets from Trans-Global Solutions, Inc.

The Kinder Morgan Blackhawk terminal consists of approximately 46 acres of

land, storage buildings, and related equipment located in Black Hawk County,

Iowa. The terminal primarily stores and transfers fertilizer and salt and

further expanded our Midwest region bulk terminal operations. The acquisition of

the repair shop, located in Jefferson County, Texas, near Beaumont, consists of

real and personal property, including parts inventory. The acquisition

facilitated and expanded the earlier acquisition of our Texas Petcoke terminals

from Trans-Global Solutions in April 2005. The operations of both acquisitions

are included in our Terminals business segment.

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(14) Allied Terminal Assets

Effective November 4, 2005, we acquired certain terminal assets from Allied

Terminals, Inc. for an aggregate consideration of approximately $13.3 million,

consisting of $12.1 million in cash and $1.2 million in assumed liabilities. The

assets primarily consisted of storage tanks, loading docks, truck racks, land

and other equipment and personal property located adjacent to our Shipyard River

bulk terminal in Charleston, South Carolina. The acquisition complemented an

ongoing capital expansion project at our Shipyard River terminal that together,

will add infrastructure in order to increase the terminal's ability to handle

increasing supplies of imported coal. The acquired assets are counted as an

external addition to our Shipyard River terminal and are included as part of our

Terminals business segment.

(15) Entrega Gas Pipeline LLC

Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega

Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East

Pipeline LLC is a limited liability company and is the sole owner of Rockies

Express Pipeline LLC. We contributed 66 2/3% of the consideration for this

purchase, which corresponded to our percentage ownership of West2East Pipeline

LLC at that time. At the time of acquisition, Sempra Energy held the remaining

33 1/3% ownership interest and contributed this same proportional amount of the

total consideration.

On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega

Pipeline, an interstate natural gas pipeline that will, when fully constructed,

consist 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. The acquired operations are included as part of our

Natural Gas Pipelines business segment.

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.

Under the terms of the purchase and sale agreement, Rockies Express Pipeline LLC

will construct the segment that extends from the Wamsutter Hub to the Cheyenne

Hub. Construction on this pipeline segment began in the second quarter of 2006,

and both pipeline segments were placed into service on February 14, 2007.

In April 2006, Rockies Express Pipeline LLC merged with and into Entrega

Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline

LLC. Going forward, the entire pipeline system (including the lines currently

being developed) will be known as the Rockies Express Pipeline. The combined

1,663-mile 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.

On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%

ownership interest in West2East Pipeline LLC (and 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 project is completed. Through our subsidiary Kinder

Morgan W2E Pipeline LLC, we will continue to operate the project but our

ownership interest decreased to 51% of the equity in the project (down from 66

2/3%). Sempra's ownership interest in West2East Pipeline LLC decreased to 25%

(down from 33 1/3%). When construction of the entire project is completed, our

ownership interest will be reduced to 50% at which time the capital accounts of

West2East Pipeline LLC will be trued up to reflect our 50% economics in the

project. We do not anticipate any additional changes in the ownership structure

of the Rockies Express Pipeline project.

West2East Pipeline LLC qualifies as a variable interest entity as defined

by Financial Accounting Standards Board Interpretation No. 46 (Revised December

2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation

of ARB No. 51," due to the fact that the total equity at risk is not sufficient

to permit the entity to finance its activities without additional subordinated

financial support provided by any parties, including equity holders.

Furthermore, following ConocoPhillips' acquisition of its ownership interest in

West2East Pipeline LLC

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on June 30, 2006, we receive 50% of the economics of the Rockies Express project

on an ongoing basis, and thus, effective June 30, 2006, we were no longer

considered the primary beneficiary of this entity as defined by FIN 46R.

Accordingly, on that date, we made the change in accounting for our investment

in West2East Pipeline LLC from full consolidation to the equity method following

the decrease in our ownership percentage.

Under the equity method, we record the costs of our investment within the

"Investments" line on our consolidated balance sheet and as changes in the net

assets of West2East Pipeline LLC occur (for example, earnings and dividends), we

recognize our proportional share of that change in the "Investment" account. We

also record our proportional share of any accumulated other comprehensive income

or loss within the "Accumulated other comprehensive loss" line on our

consolidated balance sheet.

Summary financial information as of December 31, 2006, for West2East

Pipeline LLC, which is accounted for under the equity method, is as follows (in

thousands; amounts represent 100% of investee information):

December 31,

Balance Sheet 2006

--------------------- ----------------

Current assets............................ $ 3,456

Non-current assets........................ 847,000

Current liabilities....................... 68,486

Non-current liabilities................... 790,050

Accumulated other comprehensive income.... $ (8,080)

In addition, we have guaranteed our proportionate share of West2East

Pipeline LLC's debt borrowings under a $2 billion credit facility entered into

by Rockies Express Pipeline LLC. For more information on our contingent debt,

see Note 7.

(16) April 2006 Oil and Gas Properties

On April 5, 2006, Kinder Morgan Production Company L.P. purchased various

oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P.

for an aggregate consideration of approximately $63.9 million, consisting of

$60.3 million in cash and $3.6 million in assumed liabilities. The acquisition

was effective March 1, 2006. However, we divested certain acquired properties

that are not considered candidates for carbon dioxide enhanced oil recovery,

thus reducing our total investment. We received proceeds of approximately $27.1

million from the sale of these properties.

The properties are primarily located in the Permian Basin area of West

Texas and New Mexico, produce approximately 430 barrels of oil equivalent per

day, and include some fields with potential for enhanced oil recovery

development near our current carbon dioxide operations. The acquired operations

are included as part of our CO2 business segment. Currently, we are performing

technical evaluations to confirm the carbon dioxide enhanced oil recovery

potential and generate definitive plans to develop this potential, if proven to

be economic.

(17) April 2006 Terminal Assets

In April 2006, we acquired terminal assets and operations from A&L

Trucking, L.P. and U.S. Development Group in three separate transactions for an

aggregate consideration of approximately $61.9 million, consisting of $61.6

million in cash and $0.3 million in assumed liabilities.

The first transaction included the acquisition of equipment and

infrastructure on the Houston Ship Channel that loads and stores steel products.

The acquired assets complement our nearby bulk terminal facility purchased from

General Stevedores, L.P. in July 2005. The second acquisition included the

purchase of a rail terminal at the Port of Houston that handles both bulk and

liquids products. The rail terminal complements our existing Texas petroleum

coke terminal operations and maximizes the value of our existing deepwater

terminal by providing customers with both rail and vessel transportation options

for bulk products. Thirdly, we acquired the entire membership interest of Lomita

Rail Terminal LLC, a limited liability company that owns a high-volume rail

ethanol terminal in Carson, California. The terminal serves approximately 80% of

the Southern California demand for reformulated fuel blend ethanol with

expandable offloading/distribution capacity, and the acquisition expanded our

existing rail transloading operations. All of the acquired assets are included

in our Terminals business segment. The $17.8 million of

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goodwill was assigned to our Terminals business segment and the entire amount is

expected to be deductible for tax purposes.

(18) Transload Services, LLC

Effective November 20, 2006, we acquired all of the membership interests of

Transload Services, LLC from Lanigan Holdings, LLC for an aggregate

consideration of approximately $16.8 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. Specializing

in steel processing and handling, Transload Services can inventory product,

schedule shipments and provide customers cost-effective modes of transportation.

The combined operations include over 92 acres of outside storage and 445,000

square feet of covered storage that offers customers environmentally controlled

warehouses with indoor rail and truck loading facilities for handling

temperature and humidity sensitive products. The acquired assets are included in

our Terminals business segment, and the acquisition further expanded and

diversified our existing terminals' materials services (rail transloading)

operations.

The $8.6 million of goodwill was assigned to our Terminals business

segment, and the entire amount is expected to be deductible for tax purposes. We

believe this acquisition resulted in the recognition of goodwill primarily due

to the fact that it establishes a business presence in several key markets,

taking advantage of the non-residential and highway construction demand for

steel that contributed to the fair value of acquired identifiable net assets and

liabilities exceeding our acquisition price--in the aggregate, these factors

represented goodwill. Our allocation of the purchase price to assets acquired

and liabilities assumed is preliminary, pending final determination of working

capital balances at the time of acquisition. We expect these final working

capital adjustments to be made in the first quarter of 2007.

(19) Devco USA L.L.C.

Effective December 1, 2006, we acquired all of the membership interests in

Devco USA L.L.C., an Oklahoma limited liability company, for an aggregate

consideration of approximately $7.3 million, consisting of $4.8 million in cash,

$1.6 million in common units, and $0.9 million of assumed liabilities. The

primary asset acquired was a technology based identifiable intangible asset, a

proprietary process that transforms molten sulfur into premium solid formed

pellets that are environmentally friendly, easy to handle and store, and safe to

transport. The process was developed internally by Devco's engineers and

employees. Devco, a Tulsa, Oklahoma based company, has more than 20 years of

sulfur handling expertise and we believe the acquisition and subsequent

application of this acquired technology complements our existing dry-bulk

terminal operations. We allocated $6.5 million of our total purchase price to

the value of this intangible asset, and we have included the acquisition as part

of our Terminals business segment.

(20) Roanoke, Virginia Products Terminal

Effective December 15, 2006, we acquired a refined petroleum products

terminal located in Roanoke, Virginia from Motiva Enterprises, LLC for

approximately $6.4 million in cash. The terminal has storage capacity of

approximately 180,000 barrels per day for refined petroleum products like

gasoline and diesel fuel. The terminal is served exclusively by the Plantation

Pipeline and Motiva has entered into a long-term contract to use the terminal.

The acquisition complemented the other refined products terminals we own in the

southeast region of the United States, and the acquired terminal is included as

part our Products Pipelines business segment.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement

information for the years ended December 31, 2006 and 2005, assumes that all of

the acquisitions we have made and joint ventures we have entered into since

January 1, 2005, including the ones listed above, had occurred as of January 1,

2005. We have prepared these unaudited pro forma financial results for

comparative purposes only. These unaudited pro forma financial

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results may not be indicative of the results that would have occurred if we had

completed these acquisitions and joint ventures as of January 1, 2005 or the

results that will be attained in the future. Amounts presented below are in

thousands, except for the per unit amounts:

<TABLE>

Pro Forma Year Ended

December 31,

----------------------------

2006 2005

------------ ------------

(Unaudited)

Revenues............................................. $ 8,979,852 $ 9,882,437

Operating Income..................................... 1,262,480 1,040,753

Net Income........................................... $ 974,501 $ 823,029

Basic Limited Partners' Net Income per unit.......... $ 2.05 $ 1.63

Diluted Limited Partners' Net Income per unit........ $ 2.05 $ 1.62

</TABLE>

Acquisitions Subsequent to December 31, 2006

On January 15, 2007, we announced that we had entered into an agreement

with affiliates of BP to increase our ownership interest in the Cochin pipeline

system to 100%. We purchased our original undivided 32.5% ownership interest in

the Cochin pipeline system in November 2000, and currently, we own a 49.8%

ownership interest. BP Canada Energy Company 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 standard closing conditions. The

transaction is expected to close in the first quarter of 2007, and upon closing,

we will become the operator of the pipeline.

Divestitures

Effective April 1, 2006, we sold our Douglas natural gas gathering system

and our Painter Unit fractionation facility to Momentum Energy Group, LLC for

approximately $42.5 million in cash. Our investment in 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. We used the proceeds from these

asset sales to reduce the outstanding balance on our commercial paper

borrowings.

The Douglas gathering system is comprised of approximately 1,500 miles of

4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet

per day of natural gas from approximately 650 active receipt points. Gathered

volumes are processed at our Douglas plant (which we retained), located in

Douglas, Wyoming. As part of the transaction, we executed a long-term processing

agreement with Momentum Energy Group, LLC which dedicates volumes from the

Douglas gathering system to our Douglas processing plant. The Painter Unit,

located near Evanston, Wyoming, consists of a natural gas processing plant and

fractionator, a nitrogen rejection unit, a natural gas liquids terminal, and

interconnecting pipelines with truck and rail loading facilities. Prior to the

sale, we leased the plant to BP, which operates the fractionator and the

associated Millis terminal and storage facilities for its own account.

Additionally, with regard to the natural gas operating activities of our

Douglas gathering system, we utilized certain derivative financial contracts to

offset 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, changes in the fair value of

derivative contracts that are designated and effective as cash flow hedges of

forecasted transactions are reported in other comprehensive income (not net

income) and recognized directly in equity (included within accumulated other

comprehensive income/(loss)). Amounts deferred in this way are reclassified to

net income in the same period in which the forecast transactions are recognized

in net income. However, if a hedged transaction is no longer expected to occur

by the end of the originally specified time period, because, for example, the

asset generating the hedged transaction is disposed of prior to the occurrence

of the transaction, then the net cumulative gain or loss recognized in equity

should be transferred to net income in the current period.

Accordingly, upon the sale of our Douglas gathering system, we reclassified

a net loss of $2.9 million from "Accumulated other comprehensive loss" into net

income on those derivative contracts that effectively hedged uncertain future

cash flows associated with forecasted Douglas gathering transactions. We

included the net amount of the gain, $15.1 million, within the caption "Other

expense (income)" in our accompanying consolidated statement

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<PAGE>

of income for the year ended December 31, 2006. For more information on our

accounting for derivative contracts, see Note 14.

4. Asset Retirement Obligations

We account for our legal obligations associated with the retirement of

long-lived assets pursuant to Statement of Financial Accounting Standards No.

143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides

accounting and reporting guidance for legal obligations associated with the

retirement of long-lived assets that result from the acquisition, construction

or normal operation of a long-lived asset.

SFAS No. 143 requires companies to record a liability relating to the

retirement and removal of assets used in their businesses. Under SFAS No. 143,

the fair value of asset retirement obligations are recorded as liabilities on a

discounted basis when they are incurred, which is typically at the time the

assets are installed or acquired. Amounts recorded for the related assets are

increased by the amount of these obligations. Over time, the liabilities will be

accreted for the change in their present value and the initial capitalized costs

will be depreciated over the useful lives of the related assets. The liabilities

are eventually extinguished when the asset is taken out of service.

In our CO2 business segment, we are required to plug and abandon oil and

gas wells that have been removed from service and to remove our surface wellhead

equipment and compressors. As of December 31, 2006 and 2005, we have recognized

asset retirement obligations relating to these requirements at existing sites

within our CO2 segment in the aggregate amounts of $47.2 million and $41.5

million, respectively.

In our Natural Gas Pipelines business segment, if we were to cease

providing utility services, we would be required to remove surface facilities

from land belonging to our customers and others. Our Texas intrastate natural

gas pipeline group has various condensate drip tanks and separators located

throughout its natural gas pipeline systems, as well as one inactive gas

processing plant, various laterals and gathering systems which are no longer

integral to the overall mainline transmission systems, and asbestos-coated

underground pipe which is being abandoned and retired. Our Kinder Morgan

Interstate Gas Transmission system has compressor stations which are no longer

active and other miscellaneous facilities, all of which have been officially

abandoned. We believe we can reasonably estimate both the time and costs

associated with the retirement of these facilities. As of December 31, 2006 and

2005, we have recognized asset retirement obligations relating to the businesses

within our Natural Gas Pipelines segment in the aggregate amounts of $3.1

million and $1.7 million, respectively.

We have included $1.4 million and $0.8 million, respectively, of our total

asset retirement obligations as of December 31, 2006 and December 31, 2005

within "Accrued other current liabilities" in our accompanying consolidated

balance sheets. The remaining $48.9 million obligation as of December 31, 2006

and $42.4 million obligation as of December 31, 2005 are reported separately as

non-current liabilities in our accompanying consolidated balance sheets. No

assets are legally restricted for purposes of settling our asset retirement

obligations. A reconciliation of the beginning and ending aggregate carrying

amount of our asset retirement obligations for each of the years ended December

31, 2006 and 2005 is as follows (in thousands):

<TABLE>

Year Ended December 31,

------------------------------

2006 2005

--------- ----------

Balance at beginning of period............... $ 43,227 $ 38,274

Liabilities incurred....................... 6,763 5,926

Liabilities settled........................ (2,233) (1,778)

Accretion expense.......................... 2,518 1,327

Revisions in estimated cash flows.......... -- (522)

--------- ----------

Balance at end of period..................... $ 50,275 $ 43,227

========= ==========

</TABLE>

5. Income Taxes

Components of the income tax provision applicable to continuing operations

for federal, foreign and state taxes are as follows (in thousands):

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<TABLE>

Year Ended December 31,

------------------------------------

2006 2005 2004

-------- -------- --------

Taxes currently payable:

Federal................................. $ 12,822 $ 9,604 $ 7,515

State................................... 2,339 2,112 1,497

Foreign................................. 458 322 70

-------- -------- --------

Total................................... 15,619 12,038 9,082

Taxes deferred:

Federa.................................. 1,568 8,159 5,694

State................................... 260 769 883

Foreign................................. 1,601 3,495 4,067

-------- -------- --------

Total................................... 3,429 12,423 10,644

-------- -------- --------

Total tax provision....................... $ 19,048 $ 24,461 $ 19,726

======== ======== ========

Effective tax rate........................ 1.9% 2.9% 2.3%

</TABLE>

The difference between the statutory federal income tax rate and our

effective income tax rate is summarized as follows:

<TABLE>

Year Ended December 31,

-----------------------------

2006 2005 2004

------- ------- -------

Federal income tax rate............................................. 35.0% 35.0% 35.0%

Increase (decrease) as a result of:

Partnership earnings not subject to tax............................ (35.0)% (35.0)% (35.0)%

Corporate subsidiary earnings subject to tax....................... 1.0% 1.1% 0.5%

Income tax expense attributable to corporate equity earnings....... 0.5% 1.1% 1.2%

Income tax expense attributable to foreign corporate earnings...... 0.2% 0.5% 0.5%

State taxes........................................................ 0.2% 0.2% 0.1%

------- ------- -------

Effective tax rate.................................................. 1.9% 2.9% 2.3%

======= ======= =======

</TABLE>

Our deferred tax assets and liabilities as of December 31, 2006 and 2005

result from the following (in thousands):

<TABLE>

December 31,

----------------------

2006 2005

-------- --------

Deferred tax assets:

Book accruals............................................. $ 1,431 $ 1,112

Net Operating Loss/Alternative minimum tax credits........ 2,982 1,548

Other..................................................... 1,310 1,445

-------- --------

Total deferred tax assets................................... 5,723 4,105

Deferred tax liabilities:

Property, plant and equipment............................. 69,964 63,562

Other..................................................... 11,300 10,886

-------- --------

Total deferred tax liabilities.............................. 81,264 74,448

-------- --------

Net deferred tax liabilities................................ $ 75,541 $ 70,343

======== ========

</TABLE>

We had available, at December 31, 2006, approximately $0.112 million of

foreign minimum tax credit carryforwards, which are available through 2015, and

$2.9 million of foreign and state net operating loss carryforwards, which will

expire between the years 2008 and 2025. We believe it is more likely than not

that the net operating loss carryforwards will be utilized prior to their

expiration; therefore, no valuation allowance is necessary.

6. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2006 and 2005, our property, plant and equipment

consisted of the following (in thousands):

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<TABLE>

December 31,

----------------------------

2006 2005

----------- -----------

Natural gas, liquids and carbon dioxide pipelines..................................... $ 4,309,501 $ 4,005,612

Natural gas, liquids, carbon dioxide pipeline, and terminals station equipment........ 4,508,757 4,146,328

Coal and bulk tonnage transfer, storage and services.................................. 5,946 131,265

Natural gas, liquids (including linefill), and transmix processing.................... 172,720 187,061

Other................................................................................. 844,897 625,615

Accumulated depreciation and depletion................................................ (1,604,614) (1,242,304)

----------- -----------

8,237,207 7,853,577

Land and land right-of-way............................................................ 487,123 440,497

Construction work in process.......................................................... 721,141 570,510

----------- -----------

Property, Plant and Equipment, net.................................................... $ 9,445,471 $ 8,864,584

=========== ===========

</TABLE>

Depreciation and depletion expense charged against property, plant and

equipment consists of the following (in thousands):

<TABLE>

2006 2005 2004

-------- -------- --------

Depreciation and depletion expense.. $397,525 $339,580 $285,351

</TABLE>

Casualty Gain

On August 29, 2005, Hurricane Katrina made landfall in the United States'

Gulf Coast causing widespread damage to residential and commercial real and

personal property. In addition, on September 23, 2005, Hurricane Rita struck the

Texas-Louisiana Gulf Coast causing additional damage to insured interests. The

primary assets we operate that were impacted by these storms included several

bulk and liquids terminal facilities located in the states of Louisiana and

Mississippi, and certain of our Gulf Coast liquids terminals facilities, which

are located along the Houston Ship Channel. Specifically, with regard to

physical property damage, our International Marine Terminals facility suffered

extensive property damage and a general loss of business due to the effects of

Hurricane Katrina. IMT is a Louisiana partnership owned 66 2/3% by us. It

operates a multi-purpose bulk commodity transfer terminal facility located in

Port Sulphur, Louisiana.

All of our terminal facilities affected by these storms are currently open,

and all of the facilities are covered by property casualty insurance. Some of

the facilities are also covered by business interruption insurance. To account

for our property casualty damage, we recognized repair expense related to

hurricane damage as incurred. We also transferred off our books the net book

value of the assets that were damaged or destroyed, and we offset the book value

of all damaged and destroyed assets with indemnity proceeds received (and

receivable in the future) according to the provisions of the insurance policies

in force. We also incurred capital expenditures related to the repair and

replacement of damaged assets.

When an insured asset is damaged or destroyed, the relevant accounts must

be adjusted to the date of the casualty, and settlement with the insurance

companies must be completed. The maximum amount recoverable from property damage

is the fair market value of the property at the date of loss (the replacement

value), or the amount stipulated in the insurance contract. Although net book

values are irrelevant in determining indemnifications from insurers, under

current accounting provisions, asset book values are used for accounting

purposes to measure the gain or loss resulting from casualty settlements. Also,

because indemnifications under insurance policies are based upon fair market

values, indemnifications often exceed the book value of the assets destroyed or

damaged, and any excess of insurance indemnifications over the book value of

damaged assets represents a book casualty gain.

In the fourth quarter of 2006, we reached settlements with our insurance

carriers on all of our property damage claims related to the 2005 hurricane

season, including IMT's claims. As a result of these settlements, we recognized

a property casualty gain of $15.2 million, excluding all hurricane repair and

clean-up expenses. This casualty gain represented the excess of indemnity

proceeds received or recoverable over the book value of damaged or destroyed

assets. We also collected, in 2006, property insurance indemnities of $13.1

million, and we disclosed these cash receipts separately as "Property casualty

indemnifications" within investing activities on our accompanying consolidated

statement of cash flows. In addition, as of December 31, 2006, we signed proofs

of loss totaling $8.0 million for expected future property damage proceeds, and

we received these indemnity proceeds in January 2007. With the settlement of

these claims, we released all remaining estimated property insurance receivables

and estimated property insurance-related damage claim amounts, as these

hurricane property damage claims are now

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closed; however, we will recognize additional casualty gains of approximately

$2.0 million in the first quarter of 2007 (before minority interest

allocations), based upon our final determination of the book value of the fixed

assets destroyed or damaged, and upon expected future indemnities pursuant to

flood insurance coverage.

In addition to this casualty gain, 2006 income and expense items related to

hurricane activity included the following: (i) a $2.8 million increase in

operating and maintenance expenses from hurricane repair and clean-up

activities, (ii) a $1.1 million increase in income tax expense associated with

overall hurricane income and expense items, (iii) a $0.4 million decrease in

general and administrative expenses from the allocation of overhead expenses to

hurricane related capital projects, and (iv) a $3.1 million increase in minority

interest expense related to the allocation of IMT's earnings from hurricane

income and expense items to minority interest. Combined, the hurricane income

and expense items, including the casualty gain, resulted in a total increase in

net income of $8.6 million in 2006. For the year 2006, we spent $1,058.3 million

in total capital expenditures for our continuing operations, which included

approximately $12.2 million for hurricane repair and replacement costs

(including accruals, sustaining capital expenditures for hurricane repair and

replacement costs totaled $14.2 million).

7. Investments

Our significant equity investments as of December 31, 2006 consisted of:

o Plantation Pipe Line Company (51%);

o West2East Pipeline LLC (51%);

o Red Cedar Gathering Company (49%);

o Thunder Creek Gas Services, LLC (25%);

o Cortez Pipeline Company (50%); and

o Heartland Pipeline Company (50%).

We operate and own an approximate 51% ownership interest in Plantation Pipe

Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%

interest. Each investor has an equal number of directors on Plantation's board

of directors, and board approval is required for certain corporate actions that

are considered participating rights. Therefore, we do not control Plantation

Pipe Line Company, and we account for our investment under the equity method of

accounting.

Similarly, as of December 31, 2006, we operate and own a 51% ownership

interest in West2East Pipeline LLC, a limited liability company that is the sole

owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership

interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25%

interest. As discussed in Note 2, when construction of the entire Rockies

Express Pipeline project is completed, our ownership interest will be reduced to

50% at which time the capital accounts of West2East Pipeline LLC will be trued

up to reflect our 50% economics in the project. According to the provisions of

current accounting standards, due to the fact that we will receive 50% of the

economics of the Rockies Express project on an ongoing basis, we are not

considered the primary beneficiary of West2East Pipeline LLC and thus, effective

June 30, 2006, we deconsolidated this entity and began accounting for our

investment under the equity method of accounting. As of December 31, 2006, we

had no material investment in the net assets of West2East Pipeline LLC due to

the fact that the amount of its assets, primarily property, plant and equipment,

was largely offset by the amount of its liabilities, primarily debt.

In addition, prior to the contribution of our ownership interest in Coyote

Gas Treating, LLC to Red Cedar Gathering on September 1, 2006, discussed in Note

12, we were the managing partner and owned a 50% equity interest in Coyote Gas

Treating, LLC.

Our total investments consisted of the following (in thousands):

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<TABLE>

December 31,

-----------------------

2006 2005

-------- --------

Plantation Pipe Line Company................................. $199,555 $213,072

Red Cedar Gathering Company.................................. 160,647 139,852

Thunder Creek Gas Services, LLC.............................. 37,229 37,254

Cortez Pipeline Company...................................... 16,168 17,938

Heartland Pipeline Company................................... 5,733 5,205

All Others................................................... 6,268 5,992

-------- --------

Total Equity Investments..................................... $425,600 $419,313

======== ========

</TABLE>

Our earnings from equity investments were as follows (in thousands):

<TABLE>

Year Ended December 31,

2006 2005 2004

---------- ---------- ----------

Red Cedar Gathering Company......... $ 36,310 $ 32,000 $ 14,679

Cortez Pipeline Company............. 19,173 26,319 34,179

Plantation Pipe Line Company........ 12,775 24,926 25,879

Thunder Creek Gas Services, LLC..... 2,461 2,741 2,828

Heartland Pipeline Company.......... 2,177 2,122 1,369

Coyote Gas Treating, LLC............ 1,676 2,071 2,453

All Others.......................... 1,598 1,481 1,803

-------- -------- --------

Total............................... $ 76,170 $ 91,660 $ 83,190

======== ======== ========

Amortization of excess costs........ $ (5,664) $ (5,644) $ (5,575)

======== ======== ========

</TABLE>

Summarized combined unaudited financial information for our significant

equity investments (listed above) is reported below (in thousands; amounts

represent 100% of investee financial information):

<TABLE>

Year Ended December 31,

-------------------------------------

Income Statement 2006 2005 2004

------------------------------- ---------- ---------- ---------

Revenues..................................................... $ 449,669 $ 448,382 $ 418,186

Costs and expenses........................................... 303,339 282,317 265,819

--------- --------- ---------

Earnings before extraordinary items and cumulative

effect of a change in accounting principle................. 146,330 166,065 152,367

========= ========= =========

Net income................................................... $ 146,330 $ 166,065 $152,367

========= ========= =========

</TABLE>

December 31,

------------------------

Balance Sheet 2006 2005

--------------------- ---------- ---------

Current assets...................... $ 99,523 $ 107,975

Non-current assets.................. 1,514,214 680,330

Current liabilities................. 213,610 182,549

Non-current liabilities............. 1,127,240 345,227

Partners'/owners' equity............ $ 272,887 $ 260,529

Equity Investee Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline-Currently Certificated Facilities

On August 9, 2005, the FERC approved the application of Rockies Express

Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles

of pipeline facilities in two phases. For phase I (consisting of two segments),

Rockies Express was granted authorization to construct and operate approximately

136 miles of pipeline extending northward from Rio Blanco County, Colorado to

the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct

approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County,

Colorado (segment 2). Construction of segment 1 has been completed and went into

interim service on February 24, 2006. Construction of segment 2 commenced in

mid-summer 2006, and went into service on February 14, 2007. For Phase II, which

will follow the construction of Segment 2, Rockies Express was authorized to

construct three compressor stations referred to as the Meeker, Big Hole and

Wamsutter compressor stations.

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Rockies Express Pipeline-West Project

On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline

LLC filed an application for authorization to construct and operate certain

facilities comprising its proposed "Rockies Express-West Project." This project

is the first planned segment extension of the Rockies Express' currently

certificated facilities, which includes (i) a 136-mile pipeline segment

currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in

Wyoming, and (ii) a 191-mile segment that went into service in February 2007

from Wamsutter to the Cheyenne Hub located in Weld County, Colorado. 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 issued a favorable preliminary

determination on all non-environmental issues of the 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. We expect the

FERC will complete its environmental review and issue its certificate by the end

of March 2007, and the project is expected to begin service in January 2008.

Rockies Express Pipeline-East Project

On June 13, 2006, the FERC agreed with Rockies Express' participation in

the pre-filing process for development of the "Rockies Express-East Project."

The Rockies Express-East Project will comprise approximately 635 miles of

42-inch diameter pipeline commencing from the terminus of the Rockies

Express-West pipeline to a terminus near the town of Clarington in Monroe

County, Ohio. The segment proposes to transport approximately 1.8 billion cubic

feet per day of natural gas. On August 13, 2006, the FERC issued its notice of

intent to prepare an environmental impact statement for the proposed project and

hosted nine scoping meetings from September 11 through September 15, 2006 in

various locations along the route. During this pre-filing process, Rockies

Express has encountered opposition from certain landowners in the states of

Indiana and Ohio. Rockies Express is actively participating in community

outreach meetings with landowners and agencies located in these states to

resolve any differences they may have with the project. Rockies Express is

confident that a mutual agreement and/or understanding will be reached with

these parties, and that the project is on track for a certificate application to

be filed in April 2007. The application will request that a FERC order be issued

by February 1, 2008 in order to meet both a December 31, 2008 project in-service

date for the proposed pipeline and partial compression and a June 30, 2009

in-service date for the remaining compression.

8. Intangibles

Our intangible assets include goodwill, lease value, contracts, customer

relationships and agreements.

Goodwill and Excess Investment Cost

As an investor, the price we pay to acquire an ownership interest in an

investee will most likely differ from the underlying interest in book value,

with book value representing the investee's net assets per its financial

statements. This differential relates to both discrepancies between the

investee's recognized net assets at book value and at current fair values and to

any premium we pay to acquire the investment. Under ABP No. 18, any such premium

paid by an investor, which is analogous to goodwill, must be identified.

For our investments in affiliated entities that are included in our

consolidation, the excess cost over underlying fair value of net assets is

referred to as goodwill and reported separately as "Goodwill" in our

accompanying consolidated balance sheets. Following is information related to

our goodwill as of December 31, 2006 and 2005 (in thousands):

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December 30, December 31,

------------ ------------

2006 2005

---------- ----------

Goodwill

Gross carrying amount........ $ 843,112 $ 813,101

Accumulated amortization..... (14,142) (14,142)

---------- ----------

Net carrying amount.......... 828,970 798,959

========== ==========

Goodwill is not subject to amortization but must be tested for impairment

at least annually. This test requires goodwill to be assigned to an appropriate

reporting unit and to determine if the implied fair value of the reporting

unit's goodwill is less than its carrying amount. Changes in the carrying amount

of our goodwill for each of the two years ended December 31, 2005 and 2006 are

summarized as follows (in thousands):

<TABLE>

Products Natural Gas

Pipelines Pipelines CO2 Terminals Total

--------- ----------- --------- --------- ---------

Balance as of December 31, 2004............. $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838

Acquisitions and purchase price adjs...... - 38,117 - 28,004 66,121

Disposals................................. - - - - -

Impairments............................... - - - - -

--------- ---------- --------- --------- ---------

Balance as of December 31, 2005............. $ 263,182 $ 288,435 $ 46,101 $ 201,241 $ 798,959

Acquisitions and purchase price adjs...... - - - 30,011 30,011

Disposals................................. - - - - -

Impairments............................... - - - - -

Balance as of December 31, 2006............. $ 263,182 $ 288,435 $ 46,101 $ 231,252 $ 828,970

========= ========== ========= ========= =========

</TABLE>

For our investments in entities that are not fully consolidated but instead

are included in our financial statements under the equity method of accounting,

the premium we pay that represents excess cost over underlying fair value of net

assets is referred to as equity method goodwill, and under SFAS No. 142, this

excess cost is not subject to amortization but rather to impairment testing

pursuant to APB No. 18. The impairment test under APB No. 18 considers whether

the fair value of the equity investment as a whole, not the underlying net

assets, has declined and whether that decline is other than temporary.

Therefore, in addition to our annual impairment test of goodwill, we

periodically reevaluate the amount at which we carry the excess of cost over

fair value of net assets accounted for under the equity method, as well as the

amortization period for such assets, to determine whether current events or

circumstances warrant adjustments to our carrying value and/or revised estimates

of useful lives in accordance with APB Opinion No. 18. As of both December 31,

2006 and 2005, we have reported $138.2 million in equity method goodwill within

the caption "Investments" in our accompanying consolidated balance sheets.

We also periodically reevaluate the difference between the fair value of

net assets accounted for under the equity method and our proportionate share of

the underlying book value (that is, the investee's net assets per its financial

statements) of the investee at date of acquisition. In almost all instances,

this differential, relating to the discrepancy between our share of the

investee's recognized net assets at book values and at current fair values,

represents our share of undervalued depreciable assets, and since those assets

(other than land) are subject to depreciation, we amortize this portion of our

investment cost against our share of investee earnings. We reevaluate this

differential, as well as the amortization period for such undervalued

depreciable assets, to determine whether current events or circumstances warrant

adjustments to our carrying value and/or revised estimates of useful lives in

accordance with APB Opinion No. 18. The caption "Investments" in our

accompanying consolidated balance sheets includes excess fair value of net

assets over book value costs of $177.1 million as of December 31, 2006 and

$181.7 million as of December 31, 2005.

Other Intangibles

Excluding goodwill, our other intangible assets 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 our accompanying consolidated balance sheets. Following is

information related to our intangible assets subject to amortization (in

thousands):

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December 31,

------------------------

2006 2005

---------- ----------

Lease value

Gross carrying amount............. $ 6,592 $ 6,592

Accumulated amortization.......... (1,309) (1,168)

--------- ---------

Net carrying amount............... 5,283 5,424

--------- ---------

Contracts and other

Gross carrying amount............. 231,097 221,250

Accumulated amortization.......... (23,172) (9,654)

--------- ---------

Net carrying amount............... 207,925 211,596

--------- ---------

Total Other intangibles, net........ $ 213,208 $ 217,020

========= =========

Amortization expense on our intangibles consisted of the following (in

thousands):

Year Ended December 31,

-------------------------------

2006 2005 2004

-------- -------- --------

Lease value...................... $ 141 $ 140 $ 140

Contracts and other.............. 13,518 8,599 752

-------- ------- --------

Total amortization............... $ 13,659 $ 8,739 $ 892

======== ======= ========

As of December 31, 2006, our weighted average amortization period for our

intangible assets was approximately 18.76 years. Our estimated amortization

expense for these assets for each of the next five fiscal years is approximately

$13.6 million, $13.6 million, $12.4 million, $12.2 million and $12.1 million,

respectively.

9. Debt

Short-Term Debt

Our outstanding short-term debt as of December 31, 2006 was $1,359.1

million. The balance consisted of:

o $1,098.2 million of commercial paper borrowings;

o $250.0 million in principal amount of 5.35% senior notes due August

15, 2007;

o a $5.9 million portion of 5.23% senior notes (our subsidiary, Kinder

Morgan Texas Pipeline, L.P., is the obligor on the notes); and

o a $5.0 million portion of 7.84% senior notes (our subsidiary, Central

Florida Pipe Line LLC, is the obligor on the notes).

Our outstanding short-term debt as of December 31, 2005 was $575.6 million,

which primarily consisted of $566.2 million in outstanding commercial paper

borrowings; however, we intended and had the ability to refinance all of our

short-term debt on a long-term basis under our unsecured long-term credit

facility. Accordingly, this debt balance was classified as long-term debt in our

accompanying consolidated balance sheet. As of December 31, 2006 we did not

intend to refinance all of our short-term debt on a long-term basis under our

unsecured long-term credit facility. The weighted average interest rate on all

of our borrowings was approximately 6.1779% during 2006 and 5.3019% during 2005.

Long-Term Debt

Our outstanding long-term debt, excluding market value of interest rate

swaps, as of December 31, 2006 and 2005 was $4,384.3 million and $5,220.9

million, respectively. The balances consisted of the following (in thousands):

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<TABLE>

December 31,

---------------------------

2006 2005

------------ ------------

Kinder Morgan Energy Partners, L.P. borrowings:

5.35% senior notes due August 15, 2007..................................................... $ 250,000 $ 250,000

6.30% senior notes due February 1, 2009..................................................... 250,000 250,000

7.50% senior notes due November 1, 2010..................................................... 250,000 250,000

6.75% senior notes due March 15, 2011....................................................... 700,000 700,000

7.125% senior notes due March 15, 2012...................................................... 450,000 450,000

5.00% senior notes due December 15, 2013.................................................... 500,000 500,000

5.125% senior notes due November 15, 2014................................................... 500,000 500,000

7.400% senior notes due March 15, 2031...................................................... 300,000 300,000

7.75% senior notes due March 15, 2032....................................................... 300,000 300,000

7.30% senior notes due August 15, 2033...................................................... 500,000 500,000

5.80% senior notes due March 15, 2035....................................................... 500,000 500,000

Commercial paper borrowings................................................................. 1,098,192 566,200

Subsidiary borrowings:

Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008......................... 10,000 15,000

Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010....................... 5,325 5,325

Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014.................. 49,102 54,683

Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018........ 25,000 25,000

Kinder Morgan Operating L.P. "B"-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024...... 23,700 23,700

International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025............. 40,000 40,000

Other miscellaneous subsidiary debt......................................................... 1,349 1,447

Unamortized debt discount on senior notes....................................................... (9,26) (10,46)

Current portion of long-term debt............................................................... (1,359,06) --

------------ ------------

Total Long-term debt............................................................................ $ 4,384,332 $ 5,220,887

============ ============

</TABLE>

Credit Facilities

On August 5, 2005, we increased our existing five-year unsecured bank

credit facility from $1.25 billion to $1.6 billion, and we extended the maturity

one year to August 18, 2010. The borrowing rates decreased slightly under the

extended agreement, and there were minor changes to the financial covenants as

compared to the covenants under our previous bank facility.

On February 22, 2006, we entered into a second unsecured credit facility,

in the amount of $250 million, expiring on November 21, 2006. This facility

contained borrowing rates and restrictive financial covenants that were similar

to the borrowing rates and covenants under our $1.6 billion bank facility.

Effective August 28, 2006, we terminated our $250 million unsecured

nine-month bank credit facility and we increased our existing five-year bank

credit facility from $1.6 billion to $1.85 billion. The five-year unsecured bank

credit facility remains due August 18, 2010; however, the bank facility can now

be amended to allow for borrowings up to $2.1 billion. There were no borrowings

under our five-year credit facility as of December 31, 2006 or as of December

31, 2005.

Similar to our previous bank credit facilities, our current five-year

credit facility is with a syndicate of financial institutions and Wachovia Bank,

National Association is the administrative agent. The amount available for

borrowing under our credit facility as of December 31, 2006 was reduced by:

o our outstanding commercial paper borrowings ($1,098.2 million as of

December 31, 2006);

o a combined $243 million in three letters of credit that support our

hedging of commodity price risks associated with the sale of natural

gas, natural gas liquids and crude oil;

o a combined $48 million in two letters of credit that support

tax-exempt bonds;

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o a combined $39.7 million in two letters of credit that support the

construction of our Kinder Morgan Louisiana Pipeline (a natural gas

pipeline);

o a $37.5 million letter of credit that supports our indemnification

obligations on the Series D note borrowings of Cortez Capital

Corporation; and

o a combined $16.5 million in other letters of credit supporting other

obligations of us and our subsidiaries.

Our five-year credit facility permits us to obtain bids for fixed rate

loans from members of the lending syndicate. Interest on our credit facility

accrues at our option at a floating rate equal to either:

o the administrative agent's base rate (but not less than the Federal

Funds Rate, plus 0.5%); or

o LIBOR, plus a margin, which varies depending upon the credit rating of

our long-term senior unsecured debt.

Our credit facility included the following restrictive covenants as of

December 31, 2006:

o total debt divided by earnings before interest, income taxes,

depreciation and amortization for the preceding four quarters may not

exceed:

o 5.5, in the case of any such period ended on the last day of (i)

a fiscal quarter in which we make any Specified Acquisition, or

(ii) the first or second fiscal quarter next succeeding such a

fiscal quarter; or

o 5.0, in the case of any such period ended on the last day of any

other fiscal quarter;

o certain limitations on entering into mergers, consolidations and sales

of assets;

o limitations on granting liens; and

o prohibitions on making any distribution to holders of units if an

event of default exists or would exist upon making such distribution.

In addition to normal repayment covenants, under the terms of our credit

facility, the occurrence at any time of any of the following would constitute an

event of default:

o our failure to make required payments of any item of indebtedness or

any payment in respect of any hedging agreement, provided that the

aggregate outstanding principal amount for all such indebtedness or

payment obligations in respect of all hedging agreements is equal to

or exceeds $75 million;

o our general partner's failure to make required payments of any item of

indebtedness, provided that the aggregate outstanding principal amount

for all such indebtedness is equal to or exceeds $75 million;

o adverse judgments rendered against us for the payment of money in an

aggregate amount in excess of $75 million, if this same amount remains

undischarged for a period of thirty consecutive days during which

execution shall not be effectively stayed; and

o voluntary or involuntary commencements of any proceedings or petitions

seeking our liquidation, reorganization or any other similar relief

under any federal, state or foreign bankruptcy, insolvency,

receivership or similar law.

Excluding the relatively non-restrictive specified negative covenants and

events of defaults, our credit facility does not contain any provisions designed

to protect against a situation where a party to an agreement is unable to find a

basis to terminate that agreement while its counterparty's impending financial

collapse is revealed and perhaps hastened through the default structure of some

other agreement. The credit facility does not contain a material adverse change

clause coupled with a lockbox provision; however, the facility does provide that

the margin we will pay with respect to borrowings and the facility fee that we

will pay on the total commitment will vary based

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on our senior debt investment rating. None of our debt is subject to payment

acceleration as a result of any change to our credit ratings.

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 14.

Commercial Paper Program

On August 5, 2005, we increased our commercial paper program by $350

million to provide for the issuance of up to $1.6 billion. In April 2006, we

increased our commercial paper program by $250 million to provide for the

issuance of up to $1.85 billion. Our $1.85 billion unsecured five-year bank

credit facility supports our commercial paper program, and borrowings under our

commercial paper program reduce the borrowings allowed under our credit

facility. As of December 31, 2006, we had $1,098.2 million of commercial paper

outstanding with an average interest rate of 5.4164%. The borrowings under our

commercial paper program were used principally to finance the acquisitions and

capital expansions we made during 2006 and 2005.

Senior Notes

On March 15, 2005, we paid $200 million to retire the principal amount of

our 8.0% senior notes that matured on that date. Also on March 15, 2005, we

closed a public offering of $500 million in principal amount of 5.80% senior

notes due March 15, 2035 at a price to the public of 99.746% per note. In the

offering, we received proceeds, net of underwriting discounts and commissions,

of approximately $494.4 million. We used the proceeds remaining after the

repayment of the 8.0% senior notes to reduce the outstanding balance on our

commercial paper borrowings.

As of December 31, 2006, the outstanding principal balance on the various

series of our senior notes (excluding unamortized debt discount) was $4,490.7

million. For a listing of the various outstanding series of our senior notes,

see the table above included in "--Long-term Debt."

On January 30, 2007, we completed a public offering of senior notes. We

issued a total of $1.0 billion in principal amount of senior notes, consisting

of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50%

notes due February 1, 2037. We received proceeds from the issuance of the notes,

after underwriting discounts and commissions, of approximately $992.8 million,

and we used the proceeds to reduce the borrowings under our commercial paper

program.

Subsidiary Debt

Central Florida Pipeline LLC Debt

Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As

part of our purchase price, we assumed an aggregate principal amount of $40

million of senior notes originally issued to a syndicate of eight insurance

companies. The senior notes have a fixed annual interest rate of 7.84% with

repayments in annual installments of $5 million beginning July 23, 2001. The

final payment is due July 23, 2008. Interest is payable semiannually on January

1 and July 23 of each year. In both July 2006 and July 2005, we made an annual

repayment of $5.0 million and as of December 31, 2006, Central Florida's

outstanding balance under the senior notes was $10.0 million.

Arrow Terminals L.P.

Effective October 6, 2004, we acquired Global Materials Services LLC and

its consolidated subsidiaries (see Note 3). We renamed Global Materials Services

LLC as Kinder Morgan River Terminals LLC, and as part of our purchase price, we

assumed debt of $33.7 million, consisting of third-party notes payables, current

and non-current bank borrowings, and long-term bonds payable. In October 2004,

we paid $28.4 million of the assumed debt and following these repayments, the

only remaining outstanding debt was a $5.3 million principal amount of

Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois

Development Finance Authority. Our subsidiary, Arrow Terminals L.P., is the

obligor on these bonds. The bonds have a maturity date of January 1, 2010, and

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interest on these bonds is paid and computed quarterly at the Bond Market

Association Municipal Swap Index. The bonds are collateralized by a first

mortgage on assets of Arrow's Chicago operations and a third mortgage on assets

of Arrow's Pennsylvania operations. As of December 31, 2006, the interest rate

was 4.089%. The bonds are also backed by a $5.4 million letter of credit issued

by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds

and $0.1 million of interest on the bonds for up to 45 days computed at 12% per

annum on the principal amount thereof.

Kinder Morgan Texas Pipeline, L.P. Debt

Effective August 1, 2005, we acquired a natural gas storage facility in

Liberty County, Texas (see Note 3). As part of our purchase price, we assumed

debt having a fair value of $56.5 million. We valued the debt equal to the

present value of amounts to be paid determined using an approximate interest

rate of 5.23%. The debt consisted of privately placed unsecured senior notes

with a fixed annual stated interest rate as of August 1, 2005, of 8.85%. The

assumed principal amount, along with interest, is due in monthly installments of

approximately $0.7 million. The final payment is due January 2, 2014. Our

subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the notes, and

as of December 31, 2006, KMTP's outstanding balance under the senior notes was

$49.1 million.

Additionally, the unsecured senior notes may be prepaid at any time in

amounts of at least $1.0 million at a price equal to the higher of par value or

the present value of the remaining scheduled payments of principal and interest

on the portion being prepaid. The notes also contain certain covenants similar

to those contained in our current five-year, unsecured revolving credit

facility. We do not believe that these covenants will materially affect

distributions to our partners.

Kinder Morgan Liquids Terminals LLC Debt

Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.

As part of our purchase price, we assumed debt of $87.9 million, consisting of

five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids

Terminals LLC was the obligor on the bonds, which consisted of the following:

o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due

September 1, 2019;

o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,

2022;

o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due

September 1, 2022;

o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,

2023; and

o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,

2024.

In May 2004, we exercised our right to call and retire all of the

industrial revenue bonds (other than the $3.6 million of 6.625% bonds due

February 1, 2024) prior to maturity at a redemption price of $84.3 million, plus

approximately $1.9 million for interest, prepayment premiums and redemption

fees. In October 2004, we exercised our right to call and retire the remaining

$3.6 million of bonds due February 1, 2024 prior to maturity at a redemption

price of $3.6 million, plus approximately $0.1 million for interest, prepayment

premiums and redemption fees. For both of these redemptions and retirements, we

borrowed the necessary funds under our commercial paper program. Pursuant to

Accounting Principles Board Opinion No. 26, "Early Extinguishment of Debt," we

recognized the $1.6 million excess of our reacquisition price over both the

carrying value of the bonds and unamortized debt issuance costs as a loss on

bond repurchases and we included this amount under the caption "Other, net" in

our accompanying consolidated statement of income.

In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey

from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As

part of our purchase price, we assumed $25.0 million of Economic Development

Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.

These bonds have a maturity date of January 15, 2018. Interest on these bonds is

computed on the basis of a year of 365 or 366 days, as applicable, for the

actual number of days elapsed during Commercial Paper, Daily or Weekly Rate

Periods and on the basis of a 360-day year consisting of twelve 30-day months

during a Term Rate Period. As

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of December 31, 2006, the interest rate was 3.87%. We have an outstanding letter

of credit issued by Citibank in the amount of $25.3 million that backs-up the

$25.0 million principal amount of the bonds and $0.3 million of interest on the

bonds for up to 42 days computed at 12% on a per annum basis on the principal

thereof.

Kinder Morgan Operating L.P. "B" Debt

This $23.7 million principal amount of tax-exempt bonds due April 1, 2024

was issued by the Jackson-Union Counties Regional Port District. These bonds

bear interest at a weekly floating market rate. As of December 31, 2006, the

interest rate on these bonds was 3.90%. Also, as of December 31, 2006, we had an

outstanding letter of credit issued by Wachovia in the amount of $24.1 million

that backs-up the $23.7 million principal amount of the bonds and $0.4 million

of interest on the bonds for up to 55 days computed at 12% per annum on the

principal amount thereof.

International Marine Terminals Debt

Since February 1, 2002, we have owned a 66 2/3% interest in International

Marine Terminals partnership. The principal assets owned by IMT are dock and

wharf facilities financed by the Plaquemines Port, Harbor and Terminal District

(Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue

Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.

As of December 31, 2006, the interest rate on these bonds was 3.50%.

On March 15, 2005, these bonds were refunded and the maturity date was

extended from March 15, 2006 to March 15, 2025. No other changes were made under

the bond provisions. The bonds are backed by two letters of credit issued by KBC

Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit

Reimbursement Agreement relating to the letters of credit in the amount of $45.5

million was entered into by IMT and KBC Bank. In connection with that agreement,

we agreed to guarantee the obligations of IMT in proportion to our ownership

interest. Our obligation is approximately $30.3 million for principal, plus

interest and other fees.

General Stevedores, L.P. Debt

Effective July 31, 2005, we acquired all of the partnership interests in

General Stevedores, L.P. (see Note 3). As part of our purchase price, we assumed

approximately $3.0 million in principal amount of outstanding debt, primarily

consisting of commercial bank loans. In August 2005, we paid the $3.0 million

outstanding debt balance, and following our repayment, General Stevedores, L.P.

had no outstanding debt.

Maturities of Debt

The scheduled maturities of our outstanding debt, excluding market value of

interest rate swaps, as of December 31, 2006, are summarized as follows (in

thousands):

2007.......... $1,359,069

2008.......... 11,215

2009.......... 256,377

2010.......... 261,618

2011.......... 706,410

Thereafter.... 3,148,712

----------

Total......... $5,743,401

==========

Contingent Debt

We apply the disclosure provisions of Financial Accounting Standards Board

Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements

for Guarantees, Including Indirect Guarantees of Indebtedness of Others" to our

agreements that contain guarantee or indemnification clauses. These disclosure

provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"

by requiring a guarantor to disclose certain types of guarantees, even if the

likelihood of requiring the guarantor's performance is remote. The following is

a description of our contingent debt agreements.

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Cortez Pipeline Company Debt

Pursuant to a certain Throughput and Deficiency Agreement, the partners of

Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a

subsidiary of ExxonMobil Corporation - 37% partner; and Cortez Vickers Pipeline

Company - 13% partner) are required, on a several, percentage ownership basis,

to contribute capital to Cortez Pipeline Company in the event of a cash

deficiency. The Throughput and Deficiency Agreement contractually supports the

borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez

Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund

cash deficiencies at Cortez Pipeline Company, including cash deficiencies

relating to the repayment of principal and interest on borrowings by Cortez

Capital Corporation. Parent companies of the respective Cortez Pipeline Company

partners further severally guarantee, on a percentage basis, the obligations of

the Cortez Pipeline Company partners under the Throughput and Deficiency

Agreement.

As of December 31, 2006, the debt facilities of Cortez Capital Corporation

consisted of:

o $75 million of Series D notes due May 15, 2013;

o a $125 million short-term commercial paper program; and

o a $125 million five-year committed revolving credit facility due

December 22, 2009 (to support the above-mentioned $125 million

commercial paper program).

As of December 31, 2006, Cortez Capital Corporation had $73.9 million of

commercial paper outstanding with an average interest rate of 5.3846%, the

average interest rate on the Series D notes was 7.14%, and there were no

borrowings under the credit facility.

Due to our indirect ownership of Cortez Pipeline Company through Kinder

Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez

Capital Corporation. Shell Oil Company shares our several guaranty obligations

jointly and severally; however, we are obligated to indemnify Shell for

liabilities it incurs in connection with such guaranty. With respect to Cortez's

long-term revolving credit facility, Shell was released of its guaranty

obligations on December 31, 2006; with respect to Cortez's Series D notes, in

December 2006, we entered into a letter of credit issued by JP Morgan Chase in

the amount of $37.5 million to secure our indemnification obligations to Shell

for 50% of the $75 million in principal amount of Series D notes outstanding as

of December 31, 2006; and with respect to Cortez's short-term commercial paper

borrowings, in January 2007, we entered into an additional letter of credit

issued by JP Morgan Chase in the amount of $37.5 million to secure our

indemnification obligations to Shell for 50% of the outstanding commercial paper

borrowings as of December 31, 2006.

Red Cedar Gathering Company Debt

In October 1998, Red Cedar Gathering Company sold $55 million in aggregate

principal amount of Senior Notes due October 31, 2010. The $55 million was sold

in 10 different notes in varying amounts with identical terms.

The Senior Notes are collateralized by a first priority lien on the

ownership interests, including our 49% ownership interest, in Red Cedar

Gathering Company. The Senior Notes are also guaranteed by us and the other

owner of Red Cedar Gathering Company jointly and severally. The principal is to

be repaid in seven equal installments beginning on October 31, 2004 and ending

on October 31, 2010. As of December 31, 2006, $31.4 million in principal amount

of notes were outstanding.

In the first quarter of 2007, Red Cedar plans to refinance the outstanding

balance of its existing Senior Notes through a private placement of $100 million

in principal amount of ten year fixed rate notes. Bids for the new notes were

due February 15, 2007, and the placement is expected to close on March 15, 2007.

Nassau County, Florida Ocean Highway and Port Authority Debt

Nassau County, Florida Ocean Highway and Port Authority is a political

subdivision of the State of Florida. During 1990, Ocean Highway and Port

Authority issued its Adjustable Demand Revenue Bonds in the aggregate

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principal amount of $38.5 million for the purpose of constructing certain port

improvements located in Fernandino Beach, Nassau County, Florida. The bond

indenture is for 30 years and allows the bonds to remain outstanding until

December 1, 2020. A letter of credit was issued as security for the Adjustable

Demand Revenue Bonds and was guaranteed by the parent company of Nassau

Terminals LLC, the operator of the port facilities. In July 2002, we acquired

Nassau Terminals LLC and became guarantor under the letter of credit agreement.

In December 2002, we issued a $28 million letter of credit under our credit

facilities and the former letter of credit guarantee was terminated. Principal

payments on the bonds are made on the first of December each year and

corresponding reductions are made to the letter of credit. As of December 31,

2006, this letter of credit had an outstanding balance under our credit facility

of $23.9 million.

Rockies Express Pipeline LLC Debt

On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion

five-year, unsecured revolving credit facility due April 28, 2011. This credit

facility supports a $2.0 billion commercial paper program that was established

in May 2006, and borrowings under the commercial paper program reduce the

borrowings allowed under the credit facility; this facility can be amended to

allow for borrowings up to $2.5 billion. Borrowings under the Rockies Express

credit facility and commercial paper program will be primarily used to finance

the construction of the Rockies Express interstate natural gas pipeline and to

pay related expenses, and the borrowings will not reduce the borrowings allowed

under our credit facility described in Note 9.

In addition, pursuant to certain guaranty agreements, all three member

owners of West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline,

LLC) have agreed to guarantee borrowings under the Rockies Express credit

facility and under the Rockies Express commercial paper program severally in the

same proportion as their percentage ownership of the member interests in Rockies

Express Pipeline LLC. The three member owners and their respective ownership

interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline

LLC - 51%, Sempra Energy - 25%, and ConocoPhillips - 24%. As of December 31,

2006, Rockies Express Pipeline LLC had $790.1 million of commercial paper

outstanding, and there were no borrowings under its five-year credit facility.

Accordingly, as of December 31, 2006, our contingent share of Rockies Express'

debt was $403.0 million (51% of total commercial paper borrowings).

Fair Value of Financial Instruments

Fair value as used in SFAS No. 107 "Disclosures About Fair Value of

Financial Instruments" represents the amount at which an instrument could be

exchanged in a current transaction between willing parties. The estimated fair

value of our long-term debt, including its current portion and excluding market

value of interest rate swaps, is based upon prevailing interest rates available

to us as of December 31, 2006 and December 31, 2005 and is disclosed below.

December 31, 2006 December 31, 2005

------------------------- -------------------------

Carrying Estimated Carrying Estimated

Value Fair Value Value Fair Value

---------- ---------- ---------- ----------

(In thousands)

Total Debt $5,743,401 $5,864,966 $5,220,887 $5,465,215

10. Pensions and Other Post-retirement Benefits

In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk

Terminals, Inc. in 1998, we acquired certain liabilities for pension and

post-retirement benefits. We provide medical and life insurance benefits to

current employees, their covered dependents and beneficiaries of SFPP and Kinder

Morgan Bulk Terminals. We also provide the same benefits to former salaried

employees of SFPP. Additionally, we will continue to fund these costs for those

employees currently in the plan during their retirement years. SFPP's

post-retirement benefit plan is frozen and no additional participants may join

the plan.

The noncontributory defined benefit pension plan covering the former

employees of Kinder Morgan Bulk Terminals is the Kinder Morgan, Inc. Retirement

Plan. The benefits under this plan are based primarily upon years of service and

final average pensionable earnings; however, benefit accruals were frozen as of

December 31, 1998.

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Our net periodic benefit cost for the SFPP post-retirement benefit plan were

credits of $0.3 million in 2006, $0.3 million in 2005, and $0.6 million in 2004.

The credits resulted in increases to income, largely due to amortizations of an

actuarial gain and a negative prior service cost, primarily related to the

following:

o there have been changes to the plan for both 2004 and 2005 which

reduced liabilities, creating a negative prior service cost that is

being amortized each year; and

o there was a significant drop in 2004 in the number of retired

participants reported as pipeline retirees by Burlington Northern

Santa Fe, which holds a 0.5% special limited partner interest in SFPP,

L.P.

As of December 31, 2006, we estimate our overall net periodic

post-retirement benefit cost for the year 2007 will be a credit of approximately

$0.3 million, including amortization of approximately $0.5 million of combined

prior service credits and actuarial gains from accumulated other comprehensive

income. This amount could change if there is a significant event, such as a plan

amendment or a plan curtailment, which would require a remeasurement of

liabilities. In addition, we expect to contribute approximately $0.4 million to

our post-retirement benefit plans in 2007.

On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting

for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB

Statement Nos. 87, 88, 106 and 132(R)." One of the provisions of this Statement

requires an employer with publicly traded equity securities to recognize the

overfunded or underfunded status of a defined benefit pension plan or

post-retirement benefit plan (other than a multiemployer plan) as an asset or

liability in its statement of financial position and to provide the required

disclosures as of the end of the fiscal year ending after December 15, 2006.

Following adoption of SFAS No. 158, entities will report as part of the net

benefit liability on their balance sheets amounts that have not yet been

recognized as a component of benefit expense (for example, unrecognized prior

service costs or credits, net (actuarial) gain or loss, and transition

obligation or asset) with a corresponding adjustment to accumulated other

comprehensive income.

We adopted this provision on December 31, 2006, and the primary impact on

us from adopting SFAS No. 158 was to require us to fully recognize, in our

consolidated balance sheet, both the funded status of the SFPP post-retirement

benefit plan obligation and previously unrecognized prior service credits and

actuarial gains. Both the funded status and the recorded value of our benefit

obligation for the SFPP post-retirement benefit plan as of December 31, 2006 was

$5.5 million. The following table discloses the incremental effect on our

consolidated balance sheet of applying SFAS No. 158 on December 31, 2006 (in

thousands):

<TABLE>

Before After

Application Adjustments Application

----------- ----------- -----------

Prepaid benefit cost........................ $ - $ - $ -

Accrued benefit liability................... 10,967 (5,510) 5,457

Intangible asset............................ - - -

Minority interest........................... - 28 28

Accumulated other comprehensive income...... - 5,482 5,482

</TABLE>

Multiemployer Plans

As a result of acquiring several terminal operations, primarily our

acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we

participate in several multi-employer pension plans for the benefit of employees

who are union members. We do not administer these plans and contribute to them

in accordance with the provisions of negotiated labor contracts. Other benefits

include a self-insured health and welfare insurance plan and an employee health

plan where employees may contribute for their dependents' health care costs.

Amounts charged to expense for these plans were $6.3 million for each of the

years ended December 31, 2006 and 2005.

Kinder Morgan Savings Plan

The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The

plan permits all full-time employees of Kinder Morgan, Inc. and KMGP Services

Company, Inc. to contribute between 1% and 50% of base compensation, on a

pre-tax basis, into participant accounts. In addition to a mandatory

contribution equal to 4% of

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base compensation per year for most plan participants, our general partner may

make special discretionary contributions. Certain employees' contributions are

based on collective bargaining agreements. The mandatory contributions are made

each pay period on behalf of each eligible employee. All employer contributions,

including discretionary contributions, are in the form of KMI stock that is

immediately convertible into other available investment vehicles at the

employee's discretion. Participants may direct the investment of their

contributions into a variety of investments. Plan assets are held and

distributed pursuant to a trust agreement.

For employees hired on or prior to December 31, 2004, all contributions,

together with earnings thereon, are immediately vested and not subject to

forfeiture. Employer contributions for employees hired on or after January 1,

2005 will vest on the second anniversary of the date of hire. Effective October

1, 2005, for new employees of our Terminals segment, a tiered employer

contribution schedule was implemented. This tiered schedule provides for

employer contributions of 1% for service less than one year, 2% for service

between one and two years, 3% for services between two and five years, and 4%

for service of five years or more. All employer contributions for Terminal

employees hired after October 1, 2005 will vest on the fifth anniversary of the

date of hire. The total amount charged to expense for our Savings Plan was $10.2

million during 2006 and $7.9 million during 2005. All employee contributions,

together with earnings thereon, are immediately vested and not subject to

forfeiture. Participants may direct the investment of their contributions into a

variety of investments. Plan assets are held and distributed pursuant to a trust