Kinder Morgan Energy Partners L P 10Q 2007 Q1 Quarterly report

F O R M 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007

[ ] 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		(I.R.S. Employer
of incorporation or organization)		Identification No.)

500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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

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 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 Securities Exchange Act of 1934. Large accelerated filer x 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 Securities Exchange Act of 1934). Yes o No x

The Registrant had 162,823,583 common units outstanding as of April 30, 2007.

KINDER MORGAN ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

		Page Number
	PART I. FINANCIAL INFORMATION

Item 1:	Financial Statements (Unaudited)	3
	Consolidated Statements of Income - Three Months Ended March 31, 2007 and 2006	3
	Consolidated Balance Sheets – March 31, 2007 and December 31, 2006	4
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	5
	Notes to Consolidated Financial Statements	6

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
	Critical Accounting Policies and Estimates	43
	Results of Operations	44
	Financial Condition	52
	Information Regarding Forward-Looking Statements	57

Item 3:	Quantitative and Qualitative Disclosures About Market Risk	59

Item 4:	Controls and Procedures	59



`	PART II. OTHER INFORMATION

Item 1:	Legal Proceedings	60

Item 1A:	Risk Factors	60

Item 2:	Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 3:	Defaults Upon Senior Securities	60

Item 4:	Submission of Matters to a Vote of Security Holders	60

Item 5:	Other Information	60

Item 6:	Exhibits	60

	Signature	62

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In Millions Except Per Unit Amounts)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
Revenues
Natural gas sales	$	1,404.3		$	1,691.4
Services		538.7			509.5
Product sales and other		209.2			190.7
		2,152.2			2,391.6
Costs, Expenses and Other
Gas purchases and other costs of sales		1,385.8			1,677.2
Operations and maintenance		196.7			173.4
Fuel and power		51.0			50.9
Depreciation, depletion and amortization		128.0			92.7
General and administrative		65.8			60.9
Taxes, other than income taxes		30.8			31.3
Other expense (income)		(2.2	)		—
		1,855.9			2,086.4

Operating Income		296.3			305.2

Other Income (Expense)
Earnings from equity investments		19.0			24.7
Amortization of excess cost of equity investments		(1.4	)		(1.4	)
Interest, net		(90.0	)		(75.7	)
Other, net		0.1			1.8
Minority Interest		(2.6	)		(2.4	)

Income Before Income Taxes		221.4			252.2

Income Taxes		(6.5	)		(5.5	)

Net Income	$	214.9		$	246.7

General Partner’s interest in Net Income	$	139.7		$	129.5

Limited Partners’ interest in Net Income		75.2			117.2

Net Income	$	214.9		$	246.7

Basic and Diluted Limited Partners’ Net Income per Unit	$	0.33		$	0.53

Weighted average number of units used in computation of Limited Partners’ Net Income per unit:
Basic		231.0			220.8

Diluted		231.3			221.1

Per unit cash distribution declared	$	0.83		$	0.81

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

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Millions)

(Unaudited)

	March 31,			December 31,
	2007			2006
ASSETS
Current Assets
Cash and cash equivalents	$	21.5		$	14.0
Restricted deposits		23.7			—
Accounts, notes and interest receivable, net Trade		827.5			840.8
Related parties		4.1			18.8
Inventories Products		19.3			20.4
Materials and supplies		14.5			13.8
Gas imbalances
Trade		11.0			7.8
Related parties		0.4			11.6
Gas in underground storage		42.2			8.4
Other current assets		59.1			101.1
		1,023.3			1,036.7
Property, Plant and Equipment, net		9,614.7			9,445.5
Investments		415.2			425.6
Notes receivable
Trade		0.7			1.2
Related parties		89.7			89.7
Goodwill		829.0			829.0
Other intangibles, net		209.8			213.2
Deferred charges and other assets		184.0			205.5
Total Assets	$	12,366.4		$	12,246.4


LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts	$	30.0		$	46.2
Trade		732.6			758.3
Related parties		3.4			—
Current portion of long-term debt		624.7			1,359.1
Accrued interest		54.2			82.4
Accrued taxes		48.5			37.0
Deferred revenues		18.3			20.0
Gas imbalances
Trade		8.9			15.9
Related parties		—			—
Accrued other current liabilities		531.7			566.8
		2,052.3			2,885.7
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding		5,415.0			4,384.3
Value of interest rate swaps		43.2			42.6
		5,458.2			4,426.9
Deferred revenues		18.6			18.8
Deferred income taxes		75.7			75.5
Asset retirement obligations		49.4			48.9
Other long-term liabilities and deferred credits		717.4			718.3
		6,319.3			5,288.4
Commitments and Contingencies (Note 3) Minority Interest		48.9			50.6
Partners’ Capital Common Units		2,661.7			2,743.8
Class B Units		100.6			103.3
i-Units		1,926.9			1,906.5
General Partner		129.4			109.7
Accumulated other comprehensive loss		(872.7	)		(841.6	)
		3,945.9			4,021.7
Total Liabilities and Partners’ Capital	$	12,366.4		$	12,246.4

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

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Increase/(Decrease) in Cash and Cash Equivalents In Millions)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
Cash Flows From Operating Activities Net income	$	214.9		$	246.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		128.0			92.7
Amortization of excess cost of equity investments		1.4			1.4
Gains from property casualty indemnifications		(1.8	)		—
Gains (Losses) from the sale of property, plant and equipment		(0.4	)		0.3
Earnings from equity investments		(19.0	)		(24.7	)
Distributions from equity investments		44.1			22.4
Proceeds from termination of interest rate swap agreement		15.0			—
Changes in components of working capital:
Accounts receivable		26.5			236.0
Other current assets		(29.8	)		(22.3	)
Inventories		0.4			2.9
Accounts payable		(21.6	)		(326.2	)
Accrued interest		(28.3	)		(32.0	)
Accrued liabilities		(24.9	)		(12.3	)
Accrued taxes		11.4			17.4
Other, net		(0.7	)		(26.3	)
Net Cash Provided by Operating Activities		315.2			176.0

Cash Flows From Investing Activities Acquisitions of assets		(3.9	)		(240.0	)
Additions to property, plant and equip. for expansion and maintenance projects		(245.4	)		(193.7	)
Sale of property, plant and equipment, and other net assets net of removal costs		2.0			(0.3	)
Property casualty indemnifications		8.0			—
Investments in margin deposits		(26.0	)		(33.1	)
Contributions to equity investments		(15.5	)		—
Natural gas stored underground and natural gas liquids line-fill		5.1			(9.8	)
Other		—			(3.0	)
Net Cash Used in Investing Activities		(275.7	)		(479.9	)

Cash Flows From Financing Activities Issuance of debt		1,810.2			1,148.0
Payment of debt		(1,557.0	)		(664.3	)
Repayments from loans to related party		1.1			—
Debt issue costs		(6.4	)		(0.4	)
Increase (Decrease) in cash book overdrafts		(16.3	)		11.8
Proceeds from issuance of common units		—			0.1
Contributions from minority interest		0.5			91.0
Distributions to partners: Common units		(135.3	)		(125.9	)
Class B units		(4.4	)		(4.2	)
General Partner		(120.0	)		(127.4	)
Minority interest		(4.5	)		(3.5	)
Other, net		—			(0.8	)
Net Cash (Used in) Provided by Financing Activities		(32.1	)		324.4

Effect of exchange rate changes on cash and cash equivalents		0.1			—

Increase in Cash and Cash Equivalents		7.5			20.5
Cash and Cash Equivalents, beginning of period		14.0			12.1
Cash and Cash Equivalents, end of period	$	21.5		$	32.6

Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments	$	—		$	17.0
Assets acquired by the assumption or incurrence of liabilities		0.2			—

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

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization

General

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 have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America.

We believe, however, that our disclosures are adequate to make the information presented not misleading. Our consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair presentation of our financial results for the interim periods. You should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2006.

Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC

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.

Kinder Morgan Management, LLC, referred to as “KMR” in this report, is a Delaware limited liability company. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, 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. More information on these entities and the delegation of control agreement are contained in our Annual Report on Form 10-K for the year ended December 31, 2006.

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 periods have been reclassified to conform to the current presentation.

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.

2. Acquisitions and Joint Ventures

During the first three months of 2007, we completed or made adjustments for the following acquisitions. 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. 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.

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 $62.3 million, consisting of $58.7 million in cash and $3.6 million in assumed liabilities. The acquisition was effective March 1, 2006. However, we divested certain acquired 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.

In the first quarter of 2007, we made purchase price adjustments reflecting our anticipated final purchase price settlements with the sellers. We allocated $0.1 million of our purchase price to current assets, and the remaining $62.2 million of our purchase price was allocated to “Property, Plant and Equipment, net” on our accompanying consolidated balance sheet.

Interest in Cochin Pipeline

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

The Cochin Pipeline is a multi-product liquids pipeline consisting of approximately 1,900 miles of 12-inch diameter pipe operating between Fort Saskatchewan, Alberta, and Windsor, Ontario, Canada. The entire Cochin pipeline system traverses three provinces in Canada and seven states in the United States, serving the Midwestern United States and eastern Canadian petrochemical and fuel markets. Its operations are included as part of our Products Pipelines business segment.

As of March 31, 2007, we allocated our entire purchase price to “Property, Plant and Equipment, net” on our accompanying consolidated balance sheet. Our allocation of the purchase price was preliminary, pending final determination of working capital and deferred income tax balances at the time of acquisition. We expect these final purchase price adjustments to be made in the third quarter of 2007.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the three months ended March 31, 2007 and 2006, assumes that all of the acquisitions we have made and joint ventures we have entered into since January 1, 2006, including the ones listed above, had occurred as of January 1, 2006. We have prepared these unaudited pro forma financial results for comparative purposes only, and these 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, 2006, or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:

	Pro Forma
	2007		2006
	(Unaudited)		(Unaudited)
Revenues	$	2,152.2	$	2,418.2
Operating Income	$	296.3	$	315.1
Net Income	$	214.9	$	252.9
Basic Limited Partners’ Net Income per unit	$	0.33	$	0.56
Diluted Limited Partners’ Net Income per unit	$	0.33	$	0.56

Acquisitions subsequent to March 31, 2007

On April 3, 2007, we entered into an agreement to purchase Vancouver Wharves, a bulk marine terminal, from British Columbia Railway Company, a crown corporation owned by the Province of British Columbia. The Vancouver Wharves facility is located on the north shore of the Port of Vancouver’s main harbor, and includes five deep-sea vessel berths situated on a 139-acre site. The terminal assets include significant rail infrastructure, dry bulk and liquid storage, and material handling systems which allow the terminal to handle over 3.5 million tons of cargo annually. Vancouver Wharves also has access to three major rail carriers connecting to shippers in western and central Canada, and the U.S. Pacific Northwest. The transaction is expected to close in the second quarter of 2007.

On April 30, 2007, we acquired the Trans Mountain pipeline system from KMI for $550 million. The transaction was approved by the independent board of directors of both KMI and KMR following the receipt, by each board, of separate fairness opinions from different investment banks. We paid $549 million of the purchase price on April 30, 2007, and we expect to pay the remaining $1 million by the end of the second quarter of 2007. The Trans Mountain pipeline system, which transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the State of Washington, recently completed a pump station expansion and currently transports approximately 260,000 barrels per day. An additional expansion that will increase capacity of the pipeline to 300,000 barrels per day is expected to be in service by late 2008.

3.	Litigation, Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during the three months ended March 31, 2007. Additional information with respect to these proceedings can be found in Note 16 to our audited financial statements that were filed with our Form 10-K for the year ended December 31, 2006. This Note also contains a description of any material legal proceedings that were initiated during the three months ended March 31, 2007.

Federal Energy Regulatory Commission Proceedings

SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. The tariffs and rates charged by our Pacific operations are subject to numerous ongoing proceedings at the Federal Energy Regulatory Commission, referred to in this Note as the FERC, including shippers’ complaints and protests regarding interstate rates on our Pacific operations’ pipeline systems. In general, these complaints allege the rates and tariffs charged by our Pacific operations are not just and reasonable. The issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992 and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) the capital structure to be used in computing the “starting rate base” of our Pacific operations; (iv) the level of income tax allowance we may include in our rates; and (v) the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning and environmental costs incurred by our Pacific operations.

In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. The new tax allowance policy and the FERC’s application of that policy to our Pacific operations have been appealed to the United States Court of Appeals for the District of Columbia Circuit. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service.

In this Note, we refer to SFPP, L.P. as SFPP; CALNEV Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as ConocoPhillips; Ultramar Diamond Shamrock Corporation as Ultramar; and Valero Energy Corporation as Valero. Also in this Note, we refer to the United States Court of Appeals for the District of Columbia Circuit as the D.C. Court.

Following is a listing of certain current FERC proceedings pertaining to our Pacific operations:

Proceedings	Complainants	Defendants	Summary
FERC Docket No. OR92-8 et al.	Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco (Ultramar is an intervenor).	SFPP	Consolidated proceeding involving shipper complaints against certain East Line and West Line rates. All five issues (and others) described three paragraphs above this chart are involved in these proceedings. Portions of this proceeding have been appealed (and re-appealed) to the DC Court and remanded to the FERC.
FERC Docket Nos. OR92-8-028, et al.	BP WCP; ExxonMobil; Chevron; ConocoPhillips; and Ultramar	SFPP	Proceeding involving shipper complaints against SFPP’s Watson Station rates. A settlement was reached for April 1, 1999 forward; whether SFPP owes reparations for shipments prior to that date is still before the FERC.
FERC Docket No. OR96-2 et al.	All Shippers except Chevron (which is an intervenor)	SFPP	Consolidated proceeding involving shipper complaints against all SFPP rates. All five issues (and others) described three paragraphs above this chart are involved in these proceedings. Portions of this proceeding have been appealed (and re-appealed) to the DC Court and remanded to the FERC. Among other things, income tax allowance and grandfathering issues are currently pending before the D.C. Court. Various compliance filings have been filed, and rate reductions have been implemented. With respect to the FERC’s order on the Sepulveda rate, a compliance filing has been made and requests for rehearing have been filed.
FERC Docket No. OR02-4 and OR03-5	Chevron	SFPP	Chevron initiated proceeding to permit Chevron to become complainant in OR96-2. Appealed to D.C. Court and held in abeyance pending final disposition of the OR96-2 proceedings.
FERC Docket No. OR04-3	America West Airlines; Southwest Airlines; Northwest Airlines; and Continental Airlines	SFPP	Complaint alleges that West Line and Watson Station rates are unjust and unreasonable. Watson Station issues severed and consolidated into a proceeding focused only on Watson-related issues (see above). No FERC action on complaint against West Line rates.
FERC Docket Nos. OR03-5, OR05-4 and OR05-5	BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)	SFPP	Complaints allege that SFPP’s interstate rates are not just and reasonable and that substantially changed circumstances have occurred. Complaints held in abeyance pending conclusion of other pending SFPP proceedings.

Proceedings	Complainants	Defendants	Summary
FERC Docket No. OR07-1	Tesoro	SFPP	Complaint alleges that SFPP’s North Line rates are not just and reasonable. Complaint held in abeyance pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.
FERC Docket No. OR07-2	Tesoro	SFPP	Complaint alleges that SFPP’s West Line rates are not just and reasonable. Complaint held in abeyance pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.
FERC Docket No. OR07-3	BP WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing	SFPP	Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. Complaint dismissed; requests for rehearing filed by Chevron, Tesoro and Valero.
FERC Docket No. OR07-4	BP WCP; Chevron; and ExxonMobil;	SFPP; Kinder Morgan G.P., Inc.; Kinder Morgan, Inc.	Complaint alleges that SFPP’s rates are not just and reasonable. Complaint held in abeyance pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.
FERC Docket No. OR07-5	ExxonMobil	SFPP; Kinder Morgan G.P., Inc.; Kinder Morgan, Inc.	Complaint alleges that none of Calnev’s current rates are just or reasonable. Complaint held in abeyance pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.
FERC Docket No. OR07-6	ConocoPhillips	SFPP	Complaint alleges that SFPP’s North Line indexed rate increase was not just and reasonable. Complaint dismissed.
FERC Docket No. OR07-7	Tesoro	Calnev, Kinder Morgan G.P., Inc., Kinder Morgan, Inc.	Complaint alleges that none of Calnev’s current rates are just or reasonable. Complaint held in abeyance pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.
FERC Docket No. OR07-8	BP WCP	SFPP	Complaint alleges that SFPP’s 2005 indexed rate increase was not just and reasonable. No FERC action on complaint.
FERC Docket No. IS05-230 (North Line rate case)	Shippers	SFPP	SFPP filed to increase North Line rates to reflect increased costs due to installation of new pipe between Concord and Sacramento, California. Various shippers protested. Administrative law judge decision pending before the FERC on exceptions.
FERC Docket No. IS06-283 (East Line rate case)	Shippers	SFPP	SFPP filed to increase East Line rates to reflect increased costs due to installation of new pipe between El Paso, Texas and Tucson, Arizona. Various shippers protested. Procedural schedule suspended pending resolution of, among other things, income tax allowance and grandfathering issues currently pending before the D.C. Court.

Proceedings	Complainants	Defendants	Summary
FERC Docket No. IS05-327	Shippers	SFPP	SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Various shippers protested, but FERC determined that the tariff filings were consistent with its regulations. The D.C. Court dismissed a petition for review, citing a lack of jurisdiction to review a decision by FERC not to order an investigation.
FERC Docket No. IS06-356	Shippers	SFPP	SFPP filed to increase certain rates on its pipelines pursuant to FERC’s indexing methodology. Various shippers protested, but FERC found the tariff filings consistent with its regulations. Petitions for review filed with D.C. Court. Motion to dismiss filed and pending based on D.C. Court decision in Docket No. IS05-327. FERC subsequently rescinded the index increase for the East Line rates, and SFPP requested rehearing (now pending before FERC).
FERC Docket No. IS07-137 (ULSD Surcharge)	Shippers	SFPP	SFPP filed tariffs to include a per barrel ultra low sulfur diesel (ULSD) recovery fee and a surcharge for ULSD-related litigation costs on diesel products. Various shippers protested. Tariffs accepted subject to refund and proceeding held in abeyance pending resolution of other proceedings involving SFPP. With no investigation established, SFPP rescinded ULSD litigation surcharge in compliance with FERC order. Request for rehearing filed by Chevron and Tesoro.
Motions to compel payment of interim damages (Various dockets)	Shippers	SFPP, Kinder Morgan G.P., Inc., Kinder Morgan, Inc.	Proceeding seeks payment of interim damages or escrow of funds pending resolution of various complaints and protests involving SFPP. No FERC action on motions.
FERC Docket No. IS06-296	ExxonMobil	Calnev	Calnev sought to increase its interstate rates pursuant to FERC indexing methodologies. ExxonMobil has protested and a procedural schedule is in place.

In 2003, we made aggregate payments of $44.9 million for reparations and refunds pursuant to a FERC order related to Docket No. OR92-8 et al. In 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs. Pursuant to the compliance filing, SFPP reduced its rates effective May 1, 2006. We currently estimate the impact of the rate reductions in 2007 to be approximately $25 million. In 2005, we also recorded an accrual of $105.0 million for an expense attributable to an increase in our reserves related to our rate case liability. We assume that any additional reparations and accrued interest thereon will be paid no earlier than the second quarter of 2007. 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 two separate orders issued by the FERC (on December 16, 2005 and on February 13, 2006), 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. In November 2006, in several of the proceedings, the complaining shippers sought the payment by SFPP of interim damages or the escrow of funds to pay interim damages. The FERC has not taken action on these pending motions. In November 2006, in several of the proceedings, the complaining shippers sought the payment by SFPP of interim damages or the escrow of funds to pay interim damages. The FERC has not taken action on these pending motions. Appeals for these same cases are currently pending before the U.S Court of Appeals for the D.C. Circuit. Oral arguments regarding those appeals occurred in December 2006, and we expect a court decision at any time.

In general, if the shippers are successful in proving their claims, they are entitled to reparations or refunds of any excess tariffs or rates paid during the two year period prior to the filing of their complaint, and our Pacific operations may be required to reduce the amount of its tariffs or rates for particular services. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Based on our review of these FERC proceedings, we estimate that shippers are seeking approximately $275 million in reparation and refund payments and approximately $30 million in annual rate reductions.

California Public Utilities Commission Proceedings

On April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission, referred to in this Note as the CPUC. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments.

In October 2002, the CPUC issued a resolution, referred to in this Note as the Power Surcharge Resolution, approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also required SFPP to submit cost data for 2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP’s overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC’s analysis of cost data to be submitted by SFPP demonstrates that SFPP’s California jurisdictional rates are unreasonable in any fashion. On February 21, 2003, SFPP submitted the cost data required by the CPUC, which submittal is being protested by Valero Marketing, Ultramar Inc., BP WCP, ExxonMobil and Chevron.

On December 26, 2006, Tesoro filed a complaint challenging the reasonableness of SFPP’s intrastate rates for the three-year period from December 2003 through December 2006 and requesting approximately $8 million in reparations. As a result of previous SFPP rate filings and related protests, the rates that are the subject of the Tesoro complaint are being collected subject to refund.

SFPP also has various, pending ratemaking matters before the CPUC that are unrelated to the above-referenced complaints and the Power Surcharge Resolution. Protests to these rate increase applications have been filed by various shippers. As a consequence of the protests, the related rate increases are being collected subject to refund.

All of the above matters have been consolidated and assigned to a single administrative law judge. A briefing schedule has been established with respect to the CPUC complaints and the Power Surcharge Resolution; a decision from the CPUC regarding the CPUC complaints and the Power Surcharge Resolution is expected by the third quarter of 2007. Based on our review of these CPUC proceedings, we estimate that shippers are seeking approximately $65 million in reparation and refund payments and approximately $35 million in annual rate reductions.

Carbon Dioxide Litigation

Shores and First State Bank of Denton Lawsuits

Kinder Morgan CO₂ Company, L.P. (referred to in this Note as Kinder Morgan CO₂₎, Kinder Morgan G.P., Inc., and Cortez Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed March 29, 2001). These cases were originally filed as class actions on behalf of classes of overriding royalty interest owners (Shores) and royalty interest owners (Bank of Denton) for damages relating to alleged underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit. On February 22, 2005, the trial judge dismissed both cases for lack of jurisdiction. Some of the individual plaintiffs in these cases re-filed their claims in new lawsuits (discussed below).

Armor/Reddy Lawsuit

On May 13, 2004, William Armor filed a case alleging the same claims for underpayment of royalties on carbon dioxide produced from the McElmo Dome Unit against Kinder Morgan CO₂ Company, L.P. (referred to in this Note

as Kinder Morgan CO₂) Kinder Morgan G.P., Inc., and Cortez Pipeline Company among others. Armor v. Shell Oil Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas filed May 13, 2004).

On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd. filed a case in Dallas state district court alleging the same claims for underpayment of royalties. Reddy and Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial District Court, Dallas County, Texas filed May 20, 2005). The defendants include Kinder Morgan CO₂ and Kinder Morgan Energy Partners, L.P. On June 23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the court in the Armor lawsuit ordered that the Reddy lawsuit be transferred and consolidated into the Armor lawsuit. The consolidated Armor/Reddy case is currently set for trial on June 11, 2007.

On March 5, 2007, the parties executed an agreement in principle whereby they reached an agreement to settle the lawsuit subject to their execution of a final settlement agreement. The parties are preparing the final settlement agreement, which will provide for the dismissal of the lawsuit and the plaintiffs’ claims with prejudice to being refiled.

Gerald O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas Lawsuit

Kinder Morgan CO2, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the defendants in a proceeding in the federal courts for the southern district of Texas. Gerald O. Bailey et al. v. Shell Oil Company et al., (Civil Action Nos. 05-1029 and 05-1829 in the U.S. District Court for the Southern District of Texas—consolidated by Order dated July 18, 2005). The plaintiffs are asserting claims for the underpayment of royalties on carbon dioxide produced from the McElmo Dome unit. The plaintiffs assert claims for fraud/fraudulent inducement, real estate fraud, negligent misrepresentation, breach of fiduciary and agency duties, breach of contract and covenants, violation of the Colorado Unfair Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment, and open account. Bailey also asserted claims as a private relator under the False Claims Act and for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The defendants have filed motions for summary judgment on all claims. No trial date has been set.

On March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed an agreement in principle whereby they reached an agreement to settle the claims of these plaintiffs subject to the execution of a final settlement agreement. Defendants and these plaintiffs are preparing the final settlement agreement, which will provide for the dismissal of these plaintiffs’ claims with prejudice to being refiled. The claims asserted by Bailey and the other remaining, non-settling plaintiffs are not included within the settlement.

Bridwell Oil Company Wichita County Lawsuit

On March 1, 2004, Bridwell Oil Company, one of the named plaintiffs in the above described Bailey action, filed a new matter in which it asserts claims that are virtually identical to the claims it asserts in the Bailey lawsuit. Bridwell Oil Co. v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita County, Texas filed March 1, 2004). The defendants in this action include, among others, Kinder Morgan CO2, Kinder Morgan Energy Partners, L.P., and Cortez Pipeline Company. This case has been abated pending resolution of the Bailey action discussed above.

Ptasynski Colorado Federal District Court Lawsuit

On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Bailey action discussed above, filed suit against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District Court for the District of Colorado). Ptasynski, who holds an overriding royalty

interest at McElmo Dome, asserted claims for civil conspiracy, violation of the Colorado Organized Crime Control Act, violation of Colorado antitrust laws, violation of the Colorado Unfair Practices Act, breach of fiduciary duty and confidential relationship, violation of the Colorado Payment of Proceeds Act, fraudulent concealment, breach of contract and implied duties to market and good faith and fair dealing, and civil theft and conversion. Ptasynski sought actual damages, treble damages, forfeiture, disgorgement, and declaratory and injunctive relief. The Colorado court transferred the case to Houston federal district court, and Ptasynski voluntarily dismissed the case on May 19, 2006. Ptasynski also filed an appeal in the Tenth Circuit seeking to overturn the Colorado court’s order transferring the case to Houston federal district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-1231 (10th Cir.). Briefing in the appeal was completed on November 27, 2006. On April 4, 2007, the Tenth Circuit Court of Appeals dismissed the appeal as moot in light of Ptasynksi’s voluntary dismissal of the case.

CO2 Claims Arbitration

Cortez Pipeline Company and Kinder Morgan CO2, successor to Shell CO2 Company, Ltd., were among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The arbitration arose from a dispute over a class action settlement agreement which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado. The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome Unit. The settlement imposed certain future obligations on the defendants in the underlying litigation. The plaintiff in the arbitration is an entity that was formed as part of the settlement for the purpose of monitoring compliance with the obligations imposed by the settlement agreement. The plaintiff alleged that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $12 million. The plaintiff also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million. Defendants denied that there was any breach of the settlement agreement. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On October 25, 2006, the defendants filed an application to confirm the arbitration decision in New Mexico federal district court. On November 6, 2006, the plaintiff filed a motion to vacate the arbitration award in Colorado federal district court and filed a motion to dismiss the New Mexico federal district court application for lack of jurisdiction or, alternatively, asked the New Mexico court to stay consideration of the application in favor of its motion to vacate filed in the Colorado federal district court. In January 2007, the Colorado federal district court denied the plaintiff’s motion to vacate the arbitration award, and the New Mexico federal district court denied the plaintiff’s motion to dismiss the New Mexico application to confirm or to stay the New Mexico application. Briefing on the defendants’ New Mexico application to confirm is complete. No hearing date on the application has been set.

MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 received a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company, L.P., Case No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service. This Notice, and the MMS’ position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties. The Notice of Noncompliance and Civil Penalty assesses a civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS contends that false, inaccurate, or misleading information was submitted in the 17 monthly Form 2014s containing remittance advice reflecting the royalty payments for the referenced period because they reflected Kinder Morgan CO2’s use of the Cortez Pipeline tariff as the transportation allowance. The MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 should have used its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations as amended effective June 1, 2005. The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.

Kinder Morgan CO2 disputes the Notice of Noncompliance and Civil Penalty and believes that it has meritorious defenses. The MMS has not identified any royalty underpayment amount due or otherwise issued an appealable order directing that Kinder Morgan CO2 pay additional royalties or calculate the federal government’s royalties in a different manner. If, however, the MMS were to assert such a claim, the difference between the federal royalties actually paid in the June 2005 through October 2006 period and those it is thought that the government would urge as due is estimated at approximately $2.7 million. No pre-hearing hearing date or pre-hearing schedule has been set in this matter.

MMS Order to Report and Pay

On March 20, 2007, Kinder Morgan CO2 received an “Order to Report and Pay” from the Minerals Management Service. The MMS contends that Kinder Morgan CO2 has over-reported transportation allowances and underpaid royalties in the amount of approximately $4.6 million for the period from January 1, 2005 through December 31, 2006 as a result of its use of the Cortez pipeline tariff as the transportation allowance in calculating federal royalties. As noted in the discussion of the Notice of Noncompliance and Civil Penalty proceeding, the MMS claims that the Cortez Pipeline tariff is not the proper transportation allowance and that Kinder Morgan CO2 must use its “reasonable actual costs” calculated in accordance with certain federal product valuation regulations. The MMS set a due date of April 13, 2007 for Kinder Morgan CO2’s payment of the $4.6 million in claimed additional royalties, with possible late payment charges and civil penalties for failure to pay the assessed amount. Kinder Morgan CO2 has not paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal and statement of reasons in response to the Order to Report and Pay, challenging the Order and appealing it to the Director of the MMS in accordance with 30 CFR 290.100, et seq. Also on April 19, 2007, Kinder Morgan CO2 submitted a petition to suspend compliance with the Order to Report and Pay pending the appeal.

Kinder Morgan CO2 disputes the Order to Report and Pay, and as noted above, it contends that use of the Cortez pipeline tariff as the transportation allowance for purposes of calculating federal royalties was approved by the MMS in 1984 and was affirmed as open-ended by the Interior Board of Land Appeals in the 1990s. The appeal to the MMS Director does not provide for an oral hearing. Kinder Morgan CO2 has requested the right to file additional briefing on the appeal on or before June 18, 2007.

J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on behalf of all other private royalty and overriding royalty owners in the Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New Mexico)

This case involves a purported class action against Kinder Morgan CO2 alleging that it has failed to pay the full royalty and overriding royalty (“royalty interests”) on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit in the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit. The plaintiffs allege that they were members of a class previously certified as a class action by the United States District Court for the District of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC N.M. Civ. No. 95-0012 (the “Feerer Class Action”). Plaintiffs allege that Kinder Morgan CO2’s method of paying royalty interests is contrary to the settlement of the Feerer Class Action. Kinder Morgan CO2 filed a motion to compel arbitration of this matter pursuant to the arbitration provisions contained in the Feerer Class Action settlement agreement, which motion was denied. Kinder Morgan CO2 has appealed this decision to the New Mexico Supreme Court. The New Mexico Supreme Court has set oral argument for May 7, 2007.

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2’s payments on carbon dioxide produced from the McElmo Dome Unit are currently ongoing. These audits and inquiries involve federal agencies and the State of Colorado.

Commercial Litigation Matters

Union Pacific Railroad Company Easements

SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this Note as UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to conclude in the second quarter of 2007.

SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right of way and the safety standards that govern relocations. SFPP believes that it must pay for relocation of the pipeline only when so required by the railroad’s common carrier operations, and in doing so, it need only comply with standards set forth in the federal Pipeline Safety Act in conducting relocations. In July 2006, a trial before a judge regarding the circumstances under which we must pay for relocations concluded, and the judge determined in a preliminary statement of decision that we must pay for any relocations resulting from any legitimate business purpose of the UPRR. We expect to appeal any final statement of decision to this effect. In addition, UPRR contends that it has complete discretion to cause the pipeline to be relocated at SFPP’s expense at any time and for any reason, and that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief with respect to its positions regarding relocations.

It is difficult to quantify the effects of the outcome of these cases on SFPP because SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e. for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.

United States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado).

This action was filed on June 9, 1997 pursuant to the federal False Claims Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. In 1999, these cases were consolidated and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293.

In May 2005, the Special Master issued his Report and Recommendations in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. The Special Master found that there was a prior public disclosure of the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original source of the allegations. As a result, the Special Master recommended dismissal of the Kinder Morgan defendants on jurisdictional grounds.

In May 2006, the Kinder Morgan defendants filed a Motion to Dismiss and a Motion for Sanctions. In October 2006, the United States District Court for the District of Wyoming issued its Order on Report and Recommendations of Special Master. In its Order, the Court upheld the dismissal of the claims against the Kinder Morgan defendants on jurisdictional grounds, finding that the Grynberg’s claims are based upon public disclosures and that Grynberg does not qualify as an original source. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. A procedural schedule has been issued and briefing is scheduled to be complete in the fall of 2007. There have been no significant developments in this proceeding from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Weldon Johnson and Guy Sparks, individually and as Representative of Others Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit Court, Miller County Arkansas).

On October 8, 2004, plaintiffs filed the above-captioned matter against numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC; and MidCon Corp. (the “Kinder Morgan defendants”). The complaint purports to bring a class action on behalf of those who purchased natural gas from the CenterPoint defendants from October 1, 1994 to the date of class certification.

The complaint alleges that CenterPoint Energy, Inc., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-CenterPoint defendants, including the Kinder Morgan defendants. The complaint further alleges that in exchange for CenterPoint’s purchase of such natural gas at above market prices, the non-CenterPoint defendants, including the Kinder Morgan defendants, sell natural gas to CenterPoint’s non-regulated affiliates at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The complaint purports to assert claims for fraud, unlawful enrichment and civil conspiracy against all of the defendants, and seeks relief in the form of actual, exemplary and punitive damages, interest, and attorneys’ fees. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously. There have been no significant developments in this proceeding from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Federal Investigation at Cora and Grand Rivers Coal Facilities

On June 22, 2005, we announced that the Federal Bureau of Investigation is conducting an investigation related to our coal terminal facilities located in Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal terminals that occurred from 1997 through 2001. During this time period, we sold excess coal from these two terminals for our own account, generating less than $15 million in total net sales. Excess coal is the weight gain that results from moisture absorption into existing coal during transit or storage and from scale inaccuracies, which are typical in the industry. During the years 1997 through 1999, we collected, and, from 1997 through 2001, we subsequently sold, excess coal for our own account, as we believed we were entitled to do under then-existing customer contracts. We have conducted an internal investigation of the allegations and discovered no evidence of wrongdoing or improper activities at these two terminals.

We believe that the federal authorities are also investigating coal inventory practices at one or more of our other terminals. While we have no indication of the direction of this additional investigation, our records do not reflect any sales of excess coal from our other terminals, and we are not aware of any wrongdoing or improper activities at our terminals. We are cooperating fully with federal law enforcement authorities in this investigation, and expect several of our officers and employees to be interviewed formally by federal authorities. We do not believe there is any basis for criminal charges, and we are engaged in discussions to resolve any possible criminal charges.

Queen City Railcar Litigation

Claims asserted by residents and businesses. On August 28, 2005, a railcar containing the chemical styrene began leaking styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The railcar was sent by the Westlake Chemical Corporation from Louisiana, transported by Indiana & Ohio Railway, and consigned to Westlake at its dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation of many residents and the alleged temporary closure of several businesses in the Cincinnati area. A class action complaint arising out of this accident has been settled. However, one member of the settlement class, the Estate of George W. Dameron, opted out of the settlement, and the Adminstratrix of the Dameron Estate filed a wrongful death lawsuit on November 15, 2006 in the Hamilton County Court of Common Pleas, Case No. A0609990. The complaint alleges that styrene exposure caused the death of Mr. Dameron. Kinder Morgan is not a named defendant in such lawsuit, but it is likely that Kinder Morgan will be joined as a defendant, in which case Kinder Morgan intends to vigorously defend against the estate’s claim.

Certain claims by other residents and businesses remain pending. Specifically, the settlement and final judgment does not apply to purported class action claims by residents in outlying geographic zones more than one mile from the site of the incident. Settlement discussions are proceeding with such residents. In addition, the non-Kinder Morgan defendants have agreed to settle remaining claims asserted by businesses and will obtain a release of such claims favoring all defendants, including Kinder Morgan and its affiliates, subject to the retention by all defendants of their claims against each other for contribution and indemnity. Kinder Morgan expects that a claim will be asserted by other defendants against Kinder Morgan seeking contribution or indemnity for any settlements funded exclusively by other defendants, and Kinder Morgan expects to vigorously defend against any such claims.

Claims asserted by the city of Cincinnati. On September 6, 2005, the city of Cincinnati filed a complaint on behalf of itself and in parens patriae against Westlake, Indiana and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals, Inc. and Kinder Morgan GP, Inc. in the Hamilton County Court of Common Pleas, Case No. A0507323. The plaintiff’s complaint arose out of the same railcar incident reported immediately above and alleges public nuisance, negligence, strict liability, and trespass. The complaint seeks compensatory damages in excess of $25,000, punitive damages, pre- and post-judgment interest, and attorney fees. In December 2006, the court referred the parties to mediation. The parties agreed to stay discovery until after the mediation, if necessary. No trial date has been established.

Leukemia Cluster Litigation

Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second Judicial District Court, State of Nevada, County of Washoe) (“Jernee”).

Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second Judicial District Court, State of Nevada, County of Washoe) (“Sands”).

On May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against us and several Kinder Morgan related entities and individuals and additional unrelated defendants. Plaintiffs in the Jernee matter claim that defendants negligently and intentionally failed to inspect, repair and replace unidentified segments of their pipeline and facilities, allowing “harmful substances and emissions and gases” to damage “the environment and health of human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia that, in turn, is believed to be due to exposure to industrial chemicals and toxins.” Plaintiffs purport to assert claims for wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against the same defendants and alleging the same claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial purposes with the Sands case. In May 2006, the court granted defendants’ motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants’ motions to dismiss as to the remaining counts, as well as defendants’ motions to strike portions of the complaint. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the “United States”) as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint, which motion is currently pending. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. Briefing on these motions has been completed and the motions remain pending. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the remaining claims against us in these matters are without merit and intend to defend against them vigorously. There have been no significant developments in these proceedings from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Pipeline Integrity and Releases

From time to time, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. Often these leaks and ruptures

are caused by third parties that strike and rupture our pipelines during excavation or construction. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

We believe that we conduct our operations in accordance with applicable law and many of these incidents are caused by the negligence of third parties. We seek to cooperate with state and federal regulatory authorities in connection with the clean-up of the environment caused by such leaks and ruptures and with any investigations as to the facts and circumstances surrounding the incidents.

Walnut Creek, California Pipeline Rupture

On November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District (“EBMUD”), struck and ruptured an underground petroleum pipeline owned and operated by SFPP, L.P. in Walnut Creek, California. An explosion occurred immediately following the rupture that resulted in five fatalities and several injuries to employees or contractors of Mountain Cascade. The explosion and fire also caused property damage.

On May 5, 2005, the California Division of Occupational Safety and Health (“CalOSHA”) issued two civil citations against us relating to this incident assessing civil fines of approximately $0.1 million based upon our alleged failure to mark the location of the pipeline properly prior to the excavation of the site by the contractor. On June 27, 2005, the Office of the California State Fire Marshal, Pipeline Safety Division, referred to in this report as the CSFM, issued a notice of violation against us which also alleged that we did not properly mark the location of the pipeline in violation of state and federal regulations. The CSFM assessed a proposed civil penalty of $0.5 million. The location of the incident was not our work site, nor did we have any direct involvement in the water main replacement project. We believe that SFPP acted in accordance with applicable law and regulations, and further that according to California law, excavators, such as the contractor on the project, must take the necessary steps (including excavating with hand tools) to confirm the exact location of a pipeline before using any power operated or power driven excavation equipment. Accordingly, we disagree with certain of the findings of CalOSHA and the CSFM, and we have appealed the civil penalties while, at the same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve these matters.

CalOSHA, with the assistance of the Contra Costa County District Attorney’s office, is continuing to investigate the facts and circumstances surrounding the incident for possible criminal violations. We have been notified by the Contra Costa District Attorney’s office that it intends to pursue criminal charges against us in connection with the Walnut Creek pipeline rupture. We have responded by reiterating our belief that the facts and circumstances do not warrant criminal charges. We are currently engaged in discussions with the Contra Costa District Attorney’s office in an effort to resolve any possible criminal charges, which resolution may result in Kinder Morgan agreeing to plead no contest with respect to certain criminal charges, paying a fine and agreeing to certain injunctive relief. In the event that we are able to reach such a resolution we do not expect that such resolution would have a material adverse effect on our business, financial position, results of operations or cash flows. In the event that we are not able to reach a resolution, we anticipate that the Contra Costa District Attorney will pursue criminal charges, and we intend to defend such charges vigorously.

As a result of the accident, nineteen separate lawsuits have been filed. Each of these lawsuits is currently coordinated in Contra Costa County Superior Court. There are also several cross-complaints for indemnity between the co-defendants in the coordinated lawsuits. The majority of the cases are personal injury and wrongful death actions. These are: Knox, et al. v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley v. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes, et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No. RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan, Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case No.

C05-01844); Fuentes et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C05-02286); Berry et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C06-010524); Pena et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. C06-01051); Bower et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. MSC06-02129 ); and Ross et al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No. MSC06-02299 ). These complaints all allege, among other things, that SFPP/Kinder Morgan failed to properly field mark the area where the accident occurred. All of these plaintiffs sought compensatory and punitive damages. These complaints also alleged that the general contractor who struck the pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for negligently failing to locate the pipeline. Some of these complaints also named various engineers on the project for negligently failing to draw up adequate plans indicating the bend in the pipeline. A number of these actions also named Comforce Technical Services as a defendant. Comforce supplied SFPP with temporary employees/independent contractors who performed line marking and inspections of the pipeline on behalf of SFPP. Some of these complaints also named various governmental entities—such as the City of Walnut Creek, Contra Costa County, and the Contra Costa Flood Control and Water Conservation District—as defendants.

Two of the suits are related to alleged damage to a residence near the accident site. These are: USAA v. East Bay Municipal Utility District, et al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No. C05-02312). The remaining two suits are by MCI and the welding subcontractor, Matamoros. These are: Matamoros v. Kinder Morgan Energy Partners, L.P., et al., (Contra Costa County Superior Court Case No. C05-02349); and Mountain Cascade, Inc. v. Kinder Morgan Energy Partners, L.P., et al, (Contra Costa County Superior Court Case No. C-05-02576). Like the personal injury and wrongful death suits, these lawsuits allege, among other things, that SFPP/Kinder Morgan failed to properly mark its pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs alleged property damage, while MCI and Matamoros Welding allege damage to their business as a result of SFPP/Kinder Morgan's alleged failures, as well as indemnity and other common law and statutory tort theories of recovery.

Following court ordered mediation, the Kinder Morgan defendants have settled with plaintiffs in all of the wrongful death cases and many of the personal injury and property damages cases. These settlements have either become final by order of the court or are awaiting court approval. The only civil cases which remain unsettled at present are the Bower and Ross cases (each of which alleges that the plaintiffs suffered post traumatic stress disorder as a result of witnessing the incident), as well as certain cross-claims for contribution and indemnity by and between various engineering company defendants and the Kinder Morgan defendants. The parties are currently continuing discovery and court ordered mediation on the remaining cases.

Consent Agreement Regarding Cordelia, Oakland and Donner Summit California Releases

We and SFPP have entered into an agreement in principle regarding the terms of a proposed Consent Agreement with various governmental agencies to resolve civil claims relating to the unintentional release of petroleum products during three pipeline incidents in northern California. The releases occurred (i) in the Suisun Marsh area near Cordelia in Solano County, in April 2004; (ii) in Oakland in February 2005; and (iii) near Donner Pass in April 2005. The agreement was reached with the United States Environmental Protection Agency, referred to in this Note as the EPA, Department of the Interior, Department of Justice and the National Oceanic and Atmospheric Administration, as well as the State of California Department of Fish and Game, Office of Spill Prevention and Response, and the Regional Water Quality Control Boards for the San Francisco and Lahontan regions. Under the Consent Agreement, we will agree to pay approximately $3.8 million in civil penalties, $1.3 million in natural resource damages and assessment costs and approximately $0.2 million in agency response and future remediation monitoring costs. All of the civil penalties have been reserved for as of March 31, 2007. In addition, we agreed to perform enhancements in our Pacific Operations relative to its spill prevention, response and reporting practices, the majority of which have already been implemented.

It is anticipated that the Consent Agreement will be filed with the United States District Court for the Eastern District of California in May 2007, and will become effective following a 30-day public comment period. We have substantially completed remediation and restoration activities in consultation with the appropriate state and federal regulatory agencies at the location of each release. Remaining restoration work at the Suisun Marsh and Donner Pass areas is expected to be completed in the fall of 2007.

Baker, California

In November 2004, our CALNEV Pipeline experienced a failure from external damage near Baker, California, resulting in a release of gasoline that affected approximately two acres of land in the high desert administered by The U.S. Bureau of Land Management. Remediation has been conducted and continues for product in the soils. All agency requirements have been met and the site will be closed upon completion of the soil remediation. The California Department of Fish & Game has alleged a small natural resource damage claim that is currently under review. CALNEV expects to work cooperatively with the Department of Fish & Game to resolve this claim. There have been no significant developments in this matter from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Henrico County, Virginia

On April 17, 2006, Plantation Pipe Line Company, which transports refined petroleum products across the southeastern United States and which is 51.17% owned and operated by us, experienced a pipeline release of turbine fuel from its 12-inch pipeline. The release occurred in a residential area and impacted adjacent homes, yards and common areas, as well as a nearby stream. The released product did not ignite and there were no deaths or injuries. Plantation estimates the amount of product released to be approximately 553 barrels. Immediately following the release, the pipeline was shut down and emergency remediation activities were initiated. Remediation and monitoring activities are ongoing under the supervision of the EPA, and the Virginia Department of Environmental Quality, referred to in this report as the VDEQ. Following settlement negotiations and discussions with VDEQ, Plantation agreed to pay a civil penalty of $650,000 to VDEQ as well as reimburse VDEQ for $18,341 in expenses and oversight costs to resolve the matter. Plantation will satisfy $200,000 of the civil penalty by completing a supplemental environmental project in the form of a $200,000 donation to the Henrico County Fire Department for the purchase of hazardous material spill response equipment. The agreed to Special Order on Consent must undergo public notice and comment and a hearing before the Virginia State Water Control Board before it can be finalized.

Although no assurances can be given, we believe that we have meritorious defenses to all pending actions. Furthermore, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability. We also believe that these matters will not have a material adverse effect on our business, financial position, results of operations or cash flows.

Dublin, California

In June 2006, our SFPP pipeline experienced a leak near Dublin, California, resulting in a release of product that affected a limited area along a recreation path. Product impacts were primarily limited to backfill of utilities crossing the pipeline. Remediation and monitoring activities are ongoing under the supervision of the California Department of Fish & Game. The cause of the release was outside force damage. We are currently investigating potential recovery against third parties. There have been no significant developments in this matter from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Soda Springs, California

In August 2006, our SFPP pipeline experienced a failure near Soda Springs, California, resulting in a release of product that affected a limited area along Interstate Highway 80. Product impacts were primarily limited to soil in an area between the pipeline and Interstate Highway 80. Remediation and monitoring activities are ongoing under the supervision of the California Department of Fish & Game and Nevada County. The cause of the release is currently under investigation. There have been no significant developments in this matter from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Rockies Express Pipeline LLC Wyoming Construction Incident

On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc, (a third-party contractor to Rockies Express Pipeline LLC, referred to in this Note as REX), struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group. The pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries. The cause of the incident is under investigation by the PHMSA, as well as the Wyoming Occupational Safety and Health Administration. We are cooperating with both agencies. Immediately following the incident, REX and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident. We have been contacted by attorneys representing the estate and the family of the deceased bulldozer operator regarding potential claims related to the incident. Although the internal and external investigations are currently ongoing, based upon presently available information, we believe that REX acted appropriately and in compliance with all applicable laws and regulations. There have been no significant developments in this matter from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Charlotte, North Carolina

On November 27, 2006, the Plantation Pipeline experienced a release of approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. Upon discovery of the release, Plantation immediately locked out the delivery of gasoline through that pipe to prevent further releases. Product had flowed onto the surface and into a nearby stream, which is a tributary of Paw Creek, and resulted in loss of fish and other biota. Product recovery and remediation efforts were implemented immediately, including removal of product from the stream. The line was repaired and put back into service within a few days. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources (the "NCDENR"), which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR, but does not believe that a penalty is warranted given the quality of Plantation's response efforts. There have been no significant developments in this matter from the description provided in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Environmental Matters

Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, Inc. and ST Services, Inc.

On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County. We filed our answer to the complaint on June 27, 2003, in which we denied ExxonMobil’s claims and allegations as well as included counterclaims against ExxonMobil. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, later owned by ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil performed the environmental site assessment of the terminal required prior to sale pursuant to state law. During the site assessment, ExxonMobil discovered items that required remediation and the New Jersey Department of Environmental Protection issued an order that required ExxonMobil to perform various remediation activities to remove hydrocarbon contamination at the terminal. ExxonMobil, we understand, is still remediating the site and has not been removed as a responsible party from the state’s cleanup order; however, ExxonMobil claims that the remediation continues because of GATX Terminals’ storage of a fuel additive, MTBE, at the terminal during GATX Terminals’ ownership of the terminal. When GATX Terminals sold the terminal to ST Services, the parties indemnified one another for certain environmental matters. When GATX Terminals was sold to us, GATX Terminals’ indemnification obligations, if any, to ST Services may have passed to us. Consequently, at issue is any indemnification obligation we may owe to ST Services for environmental remediation of MTBE at the terminal. The complaint seeks any and all damages related to remediating MTBE at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit for remediating MTBE at the terminal. The parties are currently involved in mandatory mediation with respect to the claims set out in the lawsuit.

The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC; Continental Oil Company; Chevron Corporation, California Superior Court, County of Los Angeles, Case No. NC041463.

We and some of our subsidiaries are defendants in a lawsuit filed in 2005 alleging claims for environmental cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18 million; however, Kinder Morgan believes that the clean up costs should be substantially less and that cleanup costs must be apportioned among all the parties to the litigation. Plaintiff also alleges that it is owed approximately $2.8 million in past rent and an unspecified amount for future rent; however, we believe that previously paid rents will offset some of the plaintiff’s rent claim and that we have certain defenses to the payment of rent allegedly owed. A trial regarding the rent issue is set for October 2007.

Currently, this lawsuit is still in a preliminary stage of discovery, and the parties to the lawsuit have engaged environmental consultants to investigate environmental conditions at the terminal and to consider remedial options for those conditions. The California Regional Water Quality Control Board is the regulatory agency overseeing the environmental investigation and expected remedial work at the terminal, having issued formal directives to Kinder Morgan, plaintiff and the other defendants in the lawsuit to investigate terminal contamination and to propose a remedial action plan to address that contamination. We are supporting a lower cost cleanup that will meet state and federal regulatory requirements. We will vigorously defend these matters and believe that the outcome will not have a material adverse effect on us.

Other Environmental

Our Kinder Morgan Transmix Company has completed discussions with the United States Environmental Protection Agency and has recently entered into a Consent Agreement and Final Order regarding allegations by the EPA that it violated certain provisions of the Clean Air Act and the Resource Conservation & Recovery Act. Kinder Morgan Transmix Company agreed to pay the EPA a total of $0.6 million for agency claims that we failed to comply with certain sampling protocols at our Indianola, Pennsylvania and Hartford Illinois transmix facilities. Further, the EPA claimed that we improperly accepted hazardous waste at our transmix facility in Indianola. The largest part of the agency’s penalty related to this claim. We also agreed to pay less than $0.1 million for related alleged sampling protocol claims at our Richmond, Virginia transmix facility, and we agreed to implement a quality assurance program audit at all of our separate transmix facilities.

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving air, water and waste violations issued by various governmental authorities related to compliance with environmental regulations. As we receive notices of non-compliance, we negotiate and settle these matters. We do not believe that these violations will have a material adverse affect on our business.

We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs issued by various regulatory authorities related to compliance with environmental regulations associated with our assets. We have established a reserve to address the costs associated with the cleanup.

In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide. See “—Pipeline Integrity and Ruptures” above for additional information with respect to ruptures and leaks from our pipelines.

Although no assurance can be given, we believe that the ultimate resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur and changing circumstances could cause these matters to have a material adverse impact. As of March 31, 2007, we have accrued an environmental reserve of $58.1 million, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

Other

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.

4. Asset Retirement Obligations

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

In our CO₂ business segment, we are required to plug and abandon oil and gas wells that have been removed from service and to remove our surface wellhead equipment and compressors. As of March 31, 2007 and December 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $47.7 million and $47.2 million, respectively, relating to these requirements at existing sites within our CO₂ business segment.

In our Natural Gas Pipelines business segment, if we were to cease providing utility services, we would be required to remove certain surface facilities and equipment from land belonging to our customers and others. We believe we can reasonably estimate both the time and costs associated with the retirement of these facilities and as of both March 31, 2007 and December 31, 2006, we have recognized asset retirement obligations in the aggregate amount of $3.1 million relating to the businesses within our Natural Gas Pipelines business segment.

We have included $1.4 million of our total asset retirement obligations as of March 31, 2007 with “Accrued other current liabilities” in our accompanying consolidated balance sheet. The remaining $49.4 million obligation is reported separately as a non-current liability. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for each of the three months ended March 31, 2007 and 2006 is as follows (in millions):

	Three Months Ended March 31,
	2007			2006
Balance at beginning of period	$	50.3		$	43.2
Liabilities incurred		—			0.1
Liabilities settled		(0.1	)		(0.4	)
Accretion expense		0.6			0.6
Revisions in estimated cash flows		—			—
Balance at end of period	$	50.8		$	43.5

5.	Distributions

On February 14, 2007, we paid a cash distribution of $0.83 per unit to our common unitholders and our Class B unitholders for the quarterly period ended December 31, 2006. KMR, our sole i-unitholder, received 1,054,082 additional i-units based on the $0.83 cash distribution per common unit. The distributions were declared on January 17, 2007, payable to unitholders of record as of January 31, 2007.

On April 18, 2007, we declared a cash distribution of $0.83 per unit for the quarterly period ended March 31, 2007. The distribution will be paid on May 14, 2007, to unitholders of record as of April 30, 2007. Our common unitholders and Class B unitholders will receive cash. KMR will receive a distribution in the form of additional i-units based on the $0.83 distribution per common unit. The number of i-units distributed will be 974,285. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.015378) will be issued. The fraction was determined by dividing:

$0.83, the cash amount distributed per common unit

$53.974, the average of KMR’s shares’ closing market prices from April 12-25, 2007, 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.

6.	Intangibles

Goodwill

For our investments in affiliated entities that are included in our consolidation, the excess cost over underlying fair value of net assets is referred to as goodwill and reported separately as “Goodwill” in our accompanying consolidated balance sheets. Goodwill is not subject to amortization but must be tested for impairment at least annually. There were no changes in the carrying amount of our goodwill for the three months ended March 31, 2007. The carrying amount of our goodwill as of March 31, 2007 and as of December 31, 2006 is summarized as follows (in millions):

	Products			Natural Gas
	Pipelines			Pipelines		CO₂			Terminals			Total
Gross carrying amount	$	268.2		$	288.4	$	48.1		$	238.4		$	843.1
Accumulated amortization		(5.0	)		—		(2.0	)		(7.1	)		(14.1	)
Net carrying amount	$	263.2		$	288.4	$	46.1		$	231.3		$	829.0

In addition, according to the provisions of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” we identify any premium or excess cost we pay over the underlying fair value of net assets acquired and accounted for as investments under the equity method of accounting. This premium or excess cost is referred to as equity method goodwill and is not subject to amortization but rather to

periodic impairment testing. As of both March 31, 2007 and December 31, 2006, we have reported $138.2 million in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.

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 millions):

	March 31,			December 31,
	2007			2006
Lease value
Gross carrying amount	$	6.6		$	6.6
Accumulated amortization		(1.3	)		(1.3	)
Net carrying amount		5.3			5.3

Contracts and other
Gross carrying amount		231.1			231.1
Accumulated amortization		(26.6	)		(23.2	)
Net carrying amount		204.5			207.9

Total Other intangibles, net	$	209.8		$	213.2

For each of the first three months of 2007 and 2006, the amortization expense on our intangibles totaled $3.4 million, and this amount primarily consisted of amortization of our contracts, customer relationships, technology-based assets and agreements.

As of March 31, 2007, the weighted average amortization period for our intangible assets was approximately 18.6 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $13.6 million, $13.3 million, $12.3 million, $12.2 million and $12.1 million, respectively.

Debt

Our outstanding short-term debt as of March 31, 2007 was $624.7 million. The balance consisted of (i) $354.3 million of commercial paper borrowings; (ii) $250.0 million in principal amount of 5.35% senior notes due August 15, 2007; (iii) a $9.5 million portion of a 5.40% long-term note payable (described below in “—Kinder Morgan Operating L.P. “A” Debt”); (iv) 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 (v) a $5.0 million portion of 7.84% senior notes (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes). The weighted average interest rate on all of our borrowings was approximately 6.51% during the first quarter of 2007 and approximately 6.00% during the first quarter of 2006.

Credit Facility

Our $1.85 billion five-year unsecured bank credit facility matures August 18, 2010 and can be amended to allow for borrowings up to $2.1 billion. Borrowings under our credit facility can be used for general corporate purposes and as a backup for our commercial paper program. There were no borrowings under our five-year credit facility as of March 31, 2007 or as of December 31, 2006.

Our five-year credit facility is with a syndicate of financial institutions and Wachovia Bank, National Association is the administrative agent. As of March 31, 2007, the amount available for borrowing under our credit facility was reduced by an aggregate amount of $740 million, consisting of (i) our outstanding commercial paper borrowings ($354.3 million as of March 31, 2007); (ii) 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; (iii) a combined $48 million in two letters of credit that support tax-exempt bonds; (iv) a combined $39.7 million in two

letters of credit that support the construction of our Kinder Morgan Louisiana Pipeline (a natural gas pipeline); (v) a $37.5 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (vi) a combined $17.5 million in other letters of credit supporting other obligations of us and our subsidiaries.

Commercial Paper Program

Our commercial paper program provides for the issuance of up to $1.85 billion of commercial paper. 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 March 31, 2007, we had $354.3 million of commercial paper outstanding with an average interest rate of approximately 5.40%. As of December 31, 2006, we had $1,098.2 million of commercial paper outstanding with an average interest rate of approximately 5.42%. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2007 and 2006.

Senior Notes

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.

Interest Rate Swaps

Information on our interest rate swaps is contained in Note 10.

Kinder Morgan Operating L.P. “A” Debt

Effective January 1, 2007, we acquired the remaining approximate 50.2% interest in the Cochin pipeline system that we did not already own (see Note 3). As part of our purchase price, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%. The principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008. The final payment is due March 31, 2012. Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and as of March 31, 2007, the outstanding balance under the note was $42.8 million.

Contingent Debt

As prescribed according to the provisions of Financial Accounting Standards Board Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” we disclose certain types of guarantees or indemnifications we have made. These disclosures cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our guarantee performance is remote. The following is a description of our contingent debt agreements as of March 31, 2007.

Cortez Pipeline Company Debt

Pursuant to a certain Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. Furthermore, due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company .

As of March 31, 2007, the debt facilities of Cortez Capital Corporation consisted of (i) $75 million of Series D notes due May 15, 2013; (ii) a $125 million short-term commercial paper program; and (iii) a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of March 31, 2007, Cortez Capital Corporation had $72.3 million of commercial paper outstanding with an average interest rate of approximately 5.39%, the average interest rate on the Series D notes was 7.14%, and there were no borrowings under the credit facility.

With respect to Cortez’s Series D notes, Shell Oil Company shares our several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for liabilities it incurs in connection with such guaranty and we entered into a letter of credit issued by JP Morgan Chase in December 2006 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 March 31, 2007. With respect to Cortez’s long-term revolving credit facility, Shell was released of its guaranty obligations on December 31, 2006, and with respect to Cortez’s short-term commercial paper borrowings, Shell was released of its guaranty obligations in the first quarter of 2007.

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 Senior Notes are collateralized by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gathering Company, and are also guaranteed by us and the other owner of Red Cedar jointly and severally. As of December 31, 2006, $31.4 million in principal amount of Senior Notes were outstanding.

On March 16, 2007, Red Cedar sold $100 million in aggregate principal amount of unsecured Senior Notes due March 16, 2017. The new Senior Notes have a fixed annual interest rate of 5.59% with repayments in annual installments of $20 million beginning March 16, 2013. The final payment is due March 16, 2017.

Red Cedar used the proceeds from the sale of these Senior Notes to (i) pay the remaining outstanding balance of $31.4 million plus accrued interest and a make-whole payment to the holders of the Senior Notes issued in 1998; and (ii) make a distribution to us and its other owner (we received a cash distribution of $32.6 million in March 2007 from the excess proceeds received by Red Cedar). Due to the fact that the new Senior Notes are not collateralized by a lien on the ownership interests of Red Cedar and are also not guaranteed by us, we are not contingently liable for any portion of the outstanding debt balance as of March 31, 2007.

Nassau County, Florida Ocean Highway and Port Authority Debt

When we acquired Nassau Terminals LLC in July 2002, we became the guarantor of a letter of credit guaranteed by the previous parent company. In December 2002, we issued a $28 million letter of credit under our then-existing credit facilities and the former letter of credit guarantee was terminated. Similar to the previous letter of credit, the December 2002 letter of credit was issued as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. Nassau Terminals LLC is the operator of the marine port facilities.

The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. Principal payments on the bonds are made on the first of December each year and corresponding reductions are made to the letter of credit. As of March 31, 2007, this letter of credit had an outstanding balance under our credit facility of $23.8 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. The credit facility, which can be amended to allow for borrowings up to $2.5 billion, 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. 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.

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 March 31, 2007, Rockies Express Pipeline LLC had $1,031.5 million of commercial paper outstanding with an average interest rate of approximately 5.41%, and there were no borrowings under its five-year credit facility. Accordingly, as of March 31, 2007, our contingent share of Rockies Express’ debt was $526.1 million (51% of total commercial paper borrowings).

For additional information regarding our debt facilities and our contingent debt agreements, see Note 9 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2006.

8.	Partners’ Capital

Limited Partner Units

As of March 31, 2007 and December 31, 2006, our partners’ capital consisted of the following limited partner units:

	March 31,	December 31,
	2007	2006
Common units	162,823,583	162,816,303
Class B units	5,313,400	5,313,400
i-units	63,355,758	62,301,676
Total limited partner units	231,492,741	230,431,379

The total limited partner units represent our limited partners’ interest and an effective 98% economic interest in us, exclusive of our general partner’s incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its incentive distribution rights.

As of March 31, 2007, our common unit totals consisted of 148,467,848 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner. As of December 31, 2006, our common unit total consisted of 148,460,568 units held by third parties, 12,631,735 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner.

On both March 31, 2007 and December 31, 2006, all of our 5,313,400 Class B units were held entirely by a wholly-owned subsidiary of KMI. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. All of our Class B units were issued to a wholly-owned subsidiary of KMI in December 2000.

On both March 31, 2007 and December 31, 2006, all of our i-units were held entirely by KMR. Our i-units are a separate class of limited partner interests in us and are not publicly traded. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common unit. Based on the preceding, KMR received a distribution of 1,054,082 i-units from us on February 14, 2007. These additional i-units distributed were based on the $0.83 per unit distributed to our common unitholders on that date.

Income Allocation and Declared Distributions

For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed.

Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels. Under the terms of our partnership agreement, our distribution of $0.83 per unit paid on February 14, 2007 for the fourth quarter of 2006 required an incentive distribution to our general partner of $138.1 million; however, according to the provisions of the KMI Annual Incentive Plan, in order for the executive officers of our general partner and KMR, and for the employees of KMGP Services Company, Inc. and KMI who operate our business to earn a non-equity cash incentive (bonus) for 2006, both we and KMI were required to meet pre-established financial performance targets. The target for us was $3.28 in cash distributions per common unit for 2006, and due to the fact that we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan. 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 incentive distribution for the fourth quarter of 2006.

The waived amount approximated an amount equal to our actual bonus payout for 2006, which was approximately 75% of our budgeted full bonus payout for 2006 of $26.5 million. Including the effect of this waiver, our distribution to unitholders for the fourth quarter of 2006 resulted in an incentive distribution payment to our general partner in the amount of $118.0 million. The waiver of $20.1 million of incentive payment for the fourth quarter of 2006 reduced our general partner’s equity earnings by $19.9 million. Our distribution of $0.80 per unit paid on February 14, 2006 for the fourth quarter of 2005 required an incentive distribution to our general partner of $125.6 million. The $138.1 million incentive distribution earned by our general partner for the fourth quarter of 2006—before the waiver, over the $125.6 million incentive distribution paid for the fourth quarter of 2005 reflects the increase in the amount distributed per unit as well as the issuance of additional units.

Our declared distribution for the first quarter of 2007 of $0.83 per unit will result in an incentive distribution to our general partner of approximately $138.8 million. This compares to our distribution of $0.81 per unit and incentive distribution to our general partner of approximately $128.3 million for the first quarter of 2006.

9.	Comprehensive Income

For the three months ended March 31, 2006, the difference between our net income and our comprehensive income resulted from unrealized gains or losses on derivative contracts utilized for hedging purposes and from foreign currency translation adjustments. In the first quarter of 2007, following our adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R)” on December 31, 2006, we also recognized changes in prior service credits and net actuarial gains as a component of our other comprehensive income. However, due to the fact that these changes represented amortized amounts included as part of our periodic post-retirement benefit expense, the changes had no effect on our comprehensive income for the period.

Our total comprehensive income was as follows (in millions):

	Three Months Ended
	March 31,
	2007			2006
Net income	$	214.9		$	246.7

Foreign currency translation adjustments		0.1			0.1
Change in fair value of derivative contracts used for hedging purposes		(101.0	)		(218.0	)
Reclassification of change in fair value of derivative contracts to net income		68.4			102.2
Reclassification of post-retirement benefit actuarial gains to net income		(0.1	)		—
Total other comprehensive income/(loss)		(32.6	)		(115.7	)

Comprehensive income/(loss)	$	182.3		$	131.0

10. Risk Management

Energy Commodity Price Risk Management

We are exposed to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products. Such changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.

Hedging effectiveness and ineffectiveness

As a result of changes in the value of derivative contracts that were not effective in offsetting undesired changes in expected cash flows (the ineffective portion of hedges), we recognized a gain of $0.6 million during the first quarter of 2007 and a loss of $0.2 million during the first quarter of 2006. All of the gains and losses we recognized as a result of hedge ineffectiveness are reported within the captions “Natural gas sales,” “Gas purchases and other costs of sales,” and “Product sales and other” in our accompanying consolidated statements of income. For each of the three months ended March 31, 2007 and 2006, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

Furthermore, we reclassified $68.4 million of “Accumulated other comprehensive loss” into earnings during the three months ended March 31, 2007, including approximately $0.1 million resulting from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period. During the first quarter of 2006, we reclassified $102.2 million of Accumulated other comprehensive loss into earnings, and none of this reclassification resulted from the discontinuance of cash flow hedges due to a determination that the forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather resulted from the hedged forecasted transactions actually affecting earnings (for example, when the forecasted sales and purchases actually occurred).

Our consolidated “Accumulated other comprehensive loss” balance reported on our accompanying consolidated balance sheets was $872.7 million as of March 31, 2007 and $841.6 million as of December 31, 2006. Included in these consolidated totals were “Accumulated other comprehensive loss” amounts associated with our commodity price risk management activities of $871.3 million as of March 31, 2007 and $838.7 million as of December 31, 2006. Approximately $374.3 million of our $871.3 million “Accumulated other comprehensive loss” amount associated with our commodity price risk management activities as of March 31, 2007 is expected to be reclassified into earnings during the next twelve months.

Fair Value of Energy Commodity Derivative Contracts

The fair values of our energy commodity derivative contracts are included in our accompanying consolidated balance sheets within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities,” and “Other long-term liabilities and deferred credits.” The following table summarizes the fair values of

our energy commodity derivative contracts associated with our commodity price risk management activities and included on our accompanying consolidated balance sheets as of March 31, 2007 and December 31, 2006 (in millions):

	March 31,			December 31,
	2007			2006
Derivatives-net asset/(liability)
Other current assets	$	43.8		$	91.9
Deferred charges and other assets		3.6			12.7
Accrued other current liabilities		(413.0	)		(431.4	)
Other long-term liabilities and deferred credits	$	(504.2	)	$	(510.2	)

As discussed in our financial statements included in our Form 10-K for the year ended December 31, 2006, we have counterparty credit risk as a result of our use of financial derivative contracts. In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of both March 31, 2007 and December 31, 2006, we had three outstanding letters of credit totaling $243.0 million in support of our hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

As of March 31, 2007, we had cash margin deposits associated with our commodity contract positions and over-the-counter swap partners totaling $23.7 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet as of March 31, 2007. As of December 31, 2006, our counterparties associated with our commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $2.3 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet as of December 31, 2006.

Interest Rate Risk Management

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. We use interest rate swap agreements to manage the interest rate risk associated with our fixed rate borrowings and 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.

Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest. These swap agreements effectively convert the interest expense associated with our senior notes from fixed rates to floating rates and result in future cash flows that vary with the market rate of interest. They therefore hedge the interest rate risk associated with our fixed rate debt obligations and hedge against changes in the fair value of our fixed rate debt due to market rate changes.

As of December 31, 2006, we were a party to interest rate swap agreements with notional principal amounts of $2.1 billion. In the first quarter of 2007, we both entered into additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $400 million and a maturity date of February 1, 2017, and terminated an existing fixed-to-floating interest rate swap agreement having a notional principal amount of $100 million and a maturity date of March 15, 2032. We received $15.0 million from the early termination of this swap agreement, and this deferred gain is being amortized over the remaining life of the original swap period.

As of March 31, 2007, a notional principal amount of $2.4 billion of these agreements effectively converts the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread. These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of March 31, 2007, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.

Hedging effectiveness and ineffectiveness

Our interest rate swap contracts have been designated as fair value hedges and meet the conditions required to assume no ineffectiveness under SFAS No. 133. Therefore, we have accounted for them using the “shortcut” method prescribed by SFAS No. 133 and accordingly, we adjust the carrying value of each swap contract to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We record interest expense equal to the variable rate payments under the swap contracts.

Fair Value of Interest Rate Swap Agreements

The differences between the fair value and the original carrying value associated with our interest rate swap agreements, that is, the derivative contracts’ changes in fair value, are included within “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” in our accompanying consolidated balance sheets. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets.

The following table summarizes the net fair value of our interest rate swap agreements associated with our interest rate risk management activities and included on our accompanying consolidated balance sheets as of March 31, 2007 and December 31, 2006 (in millions):

	March 31,			December 31,
	2007			2006
Derivatives-net asset/(liability)
Deferred charges and other assets	$	52.2		$	65.2
Other long-term liabilities and deferred credits		(23.7	)		(22.6	)
Net fair value of interest rate swaps	$	28.5		$	42.6

We also included the unamortized premium from the March 2007 termination of an interest rate swap agreement within “Value of interest rate swaps,” and as of March 31, 2007, this unamortized premium totaled $14.7 million. Furthermore, we are exposed to credit related losses in the event of nonperformance by counterparties to our interest rate swap agreements, and while we enter into derivative contracts primarily with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk. As of March 31, 2007, all of our interest rate swap agreements were with counterparties with investment grade credit ratings.

Other

Certain of our business activities expose us to foreign currency fluctuations. However, due to the limited size of this exposure, we do not believe the risks associated with changes in foreign currency will have a material adverse effect on our business, financial position, results of operations or cash flows. As a result, we do not significantly hedge our exposure to fluctuations in foreign currency.

For a fully described discussion of our risk management activities, see Note 14 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2006.

11. Reportable Segments

We divide our operations into four reportable business segments:

roducts Pipelines;

Natural Gas Pipelines;

CO₂; and

Terminals.

Following our acquisition of the Trans Mountain pipeline system from KMI on April 30, 2007, and referred to in Note 2, we will report the operations of Trans Mountain as a fifth reportable business segment. We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization, which exclude general and administrative expenses, third-party debt costs and interest expense, unallocable interest income and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies.

Our Products Pipelines segment derives its revenues primarily from the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the sale, transmission, storage and gathering of natural gas. Our CO₂ segment derives its revenues primarily from the production and sale of crude oil from fields in the Permian Basin of West Texas and from the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals.

Financial information by segment follows (in millions):

	Three Months Ended March 31,
	2007			2006
Revenues
Products Pipelines
Revenues from external customers	$	210.3		$	180.5
Intersegment revenues		—			—
Natural Gas Pipelines
Revenues from external customers		1,535.4			1,830.0
Intersegment revenues		—			—
CO2
Revenues from external customers		191.6			174.7
Intersegment revenues		—			—
Terminals
Revenues from external customers		214.9			206.4
Intersegment revenues		0.2			—
Total segment revenues		2,152.4			2,391.6
Less: Total intersegment revenues		(0.2	)		—
Total consolidated revenues	$	2,152.2		$	2,391.6

Operating expenses(a)
Products Pipelines	$	72.4		$	60.7
Natural Gas Pipelines		1,405.7			1,697.8
CO2		70.6			58.5
Terminals		115.8			115.8
Less: Total intersegment operating expenses		(0.2	)		—
Total consolidated operating expenses	$	1,664.3		$	1,932.8

Other expense (income)
Products Pipelines	$	0.5		$	—
Natural Gas Pipelines		—			—
CO2		—			—
Terminals(b)		(2.7	)		—
Total consolidated other (expense) income	$	(2.2	)	$	—

Depreciation, depletion and amortization
Products Pipelines	$	22.6		$	20.2
Natural Gas Pipelines		16.0			15.9
CO2(c)		68.9			39.3
Terminals		20.5			17.3
Total consol. depreciation, depletion and amortization	$	128.0		$	92.7

	Three Months Ended March 31,
	2007			2006
Earnings from equity investments
Products Pipelines	$	7.4		$	7.9
Natural Gas Pipelines(d)		6.4			11.2
CO2		5.2			5.6
Terminals		—			—
Total consolidated equity earnings	$	19.0		$	24.7

Amortization of excess cost of equity investments
Products Pipelines	$	0.8		$	0.8
Natural Gas Pipelines		0.1			0.1
CO2		0.5			0.5
Terminals		—			—
Total consol. amortization of excess cost of investments	$	1.4		$	1.4

Interest income
Products Pipelines	$	1.1		$	1.1
Natural Gas Pipelines		—			0.1
CO2		—			—
Terminals		—			—
Total segment interest income		1.1			1.2
Unallocated interest income		0.2			0.6
Total consolidated interest income	$	1.3		$	1.8

Other, net – income (expense)
Products Pipelines	$	0.1		$	0.1
Natural Gas Pipelines		—			0.3
CO2		—			—
Terminals		—			1.4
Total consolidated other, net – income (expense)	$	0.1		$	1.8

Income tax expense
Products Pipelines	$	2.8		$	3.1
Natural Gas Pipelines		1.4			0.3
CO2		0.8			0.1
Terminals		1.5			2.0
Total consolidated income tax expense	$	6.5		$	5.5

Segment earnings before depreciation, depletion, amortization
and amortization of excess cost of equity investments(e)
Products Pipelines	$	143.2		$	125.8
Natural Gas Pipelines		134.7			143.5
CO2		125.4			121.7
Terminals		100.5			90.0
Total segment earnings before DD&A		503.8			481.0
Total consol. depreciation, depletion and amortization		(128.0	)		(92.7	)
Total consol. amortization of excess cost of investments		(1.4	)		(1.4	)
Interest and corporate administrative expenses(f)		(159.5	)		(140.2	)
Total consolidated net income	$	214.9		$	246.7

Capital expenditures
Products Pipelines	$	36.3		$	56.7
Natural Gas Pipelines		26.9			20.5
CO2		89.6			74.2
Terminals		92.6			42.3
Total consolidated capital expenditures(g)	$	245.4		$	193.7

		March 31,		December 31,
		2007		2006
Assets
Products Pipelines	$	4,003.8	$	3,910.6
Natural Gas Pipelines		3,889.8		3,942.8
CO2		1,874.2		1,838.2
Terminals		2,466.9		2,364.0
Total segment assets		12,234.7		12,055.6
Corporate assets(h)		131.7		190.8
Total consolidated assets	$	12,366.4	$	12,246.4

______

(a)	Includes natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses, and taxes, other than income taxes.

(b)	2007 amount includes income of $1.8 million from property casualty gains associated with the 2005 Hurricane season.

(c)

Includes depreciation, depletion and amortization expense associated with (i) oil and gas producing and gas processing activities in the amount of $63.6 million for the first quarter of 2007 and $34.6 million for the first quarter of 2006; and (ii) sales and transportation services activities in the amount of $5.3 million for the first quarter of 2007 and $4.7 million for the first quarter of 2006.

(d)	2007 amount includes expense of $1.0 million associated with our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company.

(e)	Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, income taxes, and other expense (income).

(f)	Includes unallocated interest income, interest and debt expense, general and administrative expenses and minority interest expense.

(g)	Includes sustaining capital expenditures of $26.8 million and $25.7 million for the three months ended March 31, 2007 and 2006, respectively. Sustaining capital expenditures are defined as capital expenditures which do not increase the capacity of an asset.

(h)	Includes cash, cash equivalents, margin and restricted deposits, certain unallocable deferred charges, and risk management assets related to the fair value of interest rate swaps.

We do not attribute interest and debt expense to any of our reportable business segments. For the three months ended March 31, 2007 and 2006, we reported total consolidated interest expense of $91.3 million and $77.5 million, respectively.

12. 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.

Our net periodic benefit costs for the SFPP post-retirement benefit plan were credits of approximately $0.1 million in each of the first quarters of 2007 and 2006. The credits resulted in increases to income, largely due to

amortizations of an actuarial gain and a negative prior service cost. As of March 31, 2007, we estimate our overall net periodic post-retirement benefit cost for the year 2007 will be a credit of approximately $0.3 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities.

13. Related Party Transactions

Plantation Pipe Line Company Note Receivable

We own a 51.17% equity interest in Plantation Pipe Line Company. An affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004, Plantation borrowed funds of $190 million from its owners and repaid all of its outstanding debt balances. We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership interest, in exchange for a seven year note receivable bearing interest at the rate of 4.72% per annum. As of December 31, 2006, the principal amount receivable from this note was $93.1 million. We included $3.4 million of this balance within “Accounts, notes and interest receivable, net—Related parties” on our accompanying consolidated balance sheet as of December 31, 2006, and we included the remaining $89.7 million balance within “Notes receivable—Related parties.”

In January 2007, Plantation paid to us $1.1 million in principal amount under the note, and as of March 31, 2007, the principal amount receivable from this note was $92.0 million. We included $2.3 million of this balance within “Accounts, notes and interest receivable, net—Related parties” on our consolidated balance sheet as of March 31, 2007, and we included the remaining $89.7 million balance as “Notes receivable—Related parties.”

Kinder Morgan, Inc. Asset Contributions

In conjunction with our acquisition of certain Natural Gas Pipelines assets from KMI, KMI became a guarantor of approximately $733.5 million of our debt. KMI would be obligated to perform under this guarantee only if we and/or our assets were unable to satisfy our obligations.

14. Regulatory Matters

The following updates the disclosure in Note 17 to our audited financial statements that were filed with our Form 10-K for the year ended December 31, 2006 with respect to developments that occurred during the three months ended March 31, 2007.

FERC Order No. 2004

Since November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C, and 2004-D, adopting new Standards of Conduct as applied to natural gas pipelines. The primary change from existing regulation was to make such standards applicable to an interstate natural gas pipeline’s interaction with many more affiliates (referred to as “energy affiliates”), including intrastate/Hinshaw natural gas pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or within a state boundary, is regulated by an agency of that state, and all the gas it transports is consumed within that state), processors and gatherers and any company involved in natural gas or electric markets (including natural gas marketers) even if they do not ship on the affiliated interstate natural gas pipeline. Local distribution companies were excluded, however, if they do not make sales to customers not physically attached to their system. The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate.

Every interstate natural gas pipeline was required to file an Order No. 2004 compliance plan with the FERC, and on July 20, 2006, the FERC accepted our interstate pipelines’ May 19, 2005 compliance filing under Order No. 2004. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A, 2004-B, 2004-C, and 2004-D as applied to natural gas pipelines, and remanded these same orders back to the FERC.

On January 9, 2007, the FERC issued an Interim Rule, effective January 9, 2007, in response to the court’s action. In the Interim Rule, the FERC readopted the Standards of Conduct, but revised or clarified with respect to issues which had been appealed to the court. Specifically, the following changes were made:

the Standards of Conduct apply only to the relationship between interstate gas transmission pipelines and their marketing affiliates, not their energy affiliates;

all risk management personnel can be shared;

the requirement to post discretionary tariff actions was eliminated (but interstate gas pipelines must still maintain a log of discretionary tariff waivers);

lawyers providing legal advice may be shared employees; and

new interstate gas transmission pipelines are not subject to the Standards of Conduct until they commence service.

The FERC clarified that all exemptions and waivers issued under Order No. 2004 remain in effect. On January 18, 2007, the FERC issued a notice of proposed rulemaking seeking comments regarding whether or not the Interim Rule should be made permanent for natural gas transmission providers. On March 21, 2007, FERC issued an Order on Clarification and Rehearing of the Interim Rule that granted clarification that the Standards of Conduct only apply to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such gas transmission provider’s pipeline.

Notice of Inquiry – Financial Reporting

On February 15, 2007, the FERC issued a notice of inquiry seeking comment on the need for changes or revisions to the FERC’s reporting requirements contained in the financial forms for gas and oil pipelines and electric utilities. Initial comments were filed by numerous parties on March 27, 2007, and reply comments were filed on April 27, 2007.

Natural Gas Pipeline Expansion Filings

Rockies Express Pipeline-Currently Certificated Facilities

As of March 31, 2007, 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. 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, we account for our investment under the equity method of accounting.

On August 9, 2005, the FERC approved the application of Rockies Express Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of pipeline facilities in two phases. For phase I (consisting of two pipeline segments), Rockies Express was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from the Meeker Hub, located at the northern end of our TransColorado pipeline system in Rio Blanco County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1 and 2 has been completed, with interim service commencing on segment 1 on February 24, 2006, and full in-service of both segments on February 14, 2007. For phase II, Rockies Express was authorized to construct three compressor stations referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations are currently under construction and are planned to be in

service in the fourth quarter of 2007. Construction of the Big Hole compressor station is planned to commence in the fourth quarter of 2008, in order to meet an expected in-service date of June 30, 2009.

Rockies Express Pipeline-West Project

On April 19, 2007, the FERC issued a final order approving the Rockies Express application for authorization to construct and operate certain facilities comprising its proposed “Rockies Express-West Project.” This project is the first planned segment extension of the Rockies Express’ currently certificated facilities, and it 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.

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 638 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 most of these parties, and on April 30, 2007, Rockies Express filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the Rockies Express East Project. The application requests that a FERC order be issued by February 1, 2008 in order to meet both a December 30, 2008 project in-service date for the proposed pipeline and partial compression, and a June 30, 2009 in-service date for the remaining compression.

TransColorado Pipeline

On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company’s application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” Upon implementation, this project will facilitate the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado.

Kinder Morgan Louisiana Pipeline

On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with the FERC requesting approval to construct and operate our Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including KMI’s Natural Gas Pipeline Company of America. The project is supported by fully subscribed capacity and long-term customer commitments with Chevron and Total. The entire approximately $500 million project is expected to be in service in the second quarter of 2009.

On March 15, 2007, the FERC issued a preliminary determination that the authorizations requested, subject to some minor modifications, will be in the public interest. This order does not consider or evaluate any of the environmental issues in this proceeding. On April 19, 2007, the FERC issued the final Environmental Impact Statement, which addresses the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental

Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts; however, we are still awaiting final FERC approval of the project.

Notice of Proposed Rulemaking – Natural Gas Price Transparency

On April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos. RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section 23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC proposes to revise its regulations to (i) require that intrastate pipelines post daily the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments in order to make available the information to track daily flows of natural gas throughout the United States; and (ii) require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC in order to make possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricing in that market, and determine the size of the fixed-price trading market that produces the information. The FERC believes these revisions to its regulations will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. Since this is a proposed rulemaking in which the FERC will take into account comments and reply comments from industry participants, it is not clear what ramifications the final rulemaking will have on the business of our intrastate and interstate pipeline companies.

15. Recent Accounting Pronouncements

EITF 04-5

In June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5, or EITF 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” EITF 04-5 provides guidance for purposes of assessing whether certain limited partners rights might preclude a general partner from controlling a limited partnership.

For general partners of all new limited partnerships formed, and for existing limited partnerships for which the partnership agreements are modified, the guidance in EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 did not have an effect on our consolidated financial statements.

Nonetheless, as a result of EITF 04-5, as of January 1, 2006, our financial statements are consolidated into the consolidated financial statements of KMI. Notwithstanding the consolidation of our financial statements into the consolidated financial statements of KMI pursuant to EITF 04-5, KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. The determination of responsibility for payment among entities in our consolidated group of subsidiaries was not impacted by the adoption of EITF 04-5.

SFAS No. 155

On February 16, 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments.” This Statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis. For us, this Statement became effective January 1, 2007. Adoption of this Statement had no effect on our consolidated financial statements.

SFAS No. 156

On March 17, 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This Statement amends SFAS No. 140 and addresses the recognition and measurement of separately recognized servicing assets and liabilities, such as those common with mortgage securitization activities, and provides an approach to simplify efforts to obtain hedge-like (offset) accounting by permitting a servicer that uses derivative financial instruments to offset risks on servicing to report both the derivative financial instrument and related servicing asset or liability by using a consistent measurement attribute—fair value. For us, this Statement became effective January 1, 2007. Adoption of this Statement had no effect on our consolidated financial statements.

EITF 06-3

On June 28, 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: (i) 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 (ii) 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 on a prospective basis, the adoption of EITF 06-3 had no effect on our consolidated financial statements.

FIN 48

In July 2006, the FASB issued Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which became effective January 1, 2007. FIN 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate resolution.

Our adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect adjustment to “Partners’ Capital” on our consolidated balance sheet. At January 1, 2007, we had $3.2 million of unrecognized tax benefits on our consolidated balance sheet, of which, $0.7 million would affect the effective income tax rate in future periods. Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense. We had $1.1 million of accrued interest and no accrued penalties as of January 1, 2007. We believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $1.3 million in the next 12 months. In addition, we have U.S. and state tax years open to examination for the periods 2003 – 2006.

SAB 108

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin 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 December 31, 2006, and the adoption of this Bulletin had no effect on our consolidated financial statements.

SFAS No. 157

On September 15, 2006, the FASB issued 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 to 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.

SFAS No. 159

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement provides companies with an option to report selected financial assets and liabilities at fair value. The Statement’s objective is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. The Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities.

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following information should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2006.

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.

Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in our Annual Report on Form 10-K for the year ended December 31, 2006. There have not been any significant changes in these policies and estimates during the three months ended March 31, 2007.

Results of Operations

Consolidated

		Three Months Ended March 31,
		2007			2006
		(In millions)
Earnings before depreciation, depletion and amortization Expense and amortization of excess cost of equity investments
Products Pipelines	$	143.2		$	125.8
Natural Gas Pipelines		134.7			143.5
CO₂		125.4			121.7
Terminals		100.5			90.0
Segment earnings before depreciation, depletion and amortization Expense and amortization of excess cost of equity investments(a)(b)		503.8			481.0

Depreciation, depletion and amortization expense		(128.0	)		(92.7	)
Amortization of excess cost of equity investments		(1.4	)		(1.4	)
Interest and corporate administrative expenses(c)		(159.5	)		(140.2	)
Net income	$	214.9		$	246.7

__________

(a) Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, income taxes, and other expense (income). Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, fuel and power expenses, and taxes, other than income taxes.

(b) 2007 amount includes (i) other income of $1.8 million to our Terminals business segment from property casualty gains associated with the 2005 Hurricane season; and (ii) expense of $1.0 million to our Natural Gas Pipelines business segment associated with our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company.

(c) Includes unallocated interest income, interest and debt expense, general and administrative expenses (including unallocated litigation and environmental expenses) and minority interest expense.

Driven by incremental earnings from our Products Pipelines, CO₂ and Terminals business segments in the first quarter of 2007, when compared to the same prior year period, our net income for the first three months of 2007 was $214.9 million ($0.33 per diluted unit) on revenues of $2,152.2 million. This compares with net income of $246.7 million ($0.53 per diluted unit) on revenues of $2,391.6 million in the first quarter of 2006.

Because our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash consists primarily of all our cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. We also use segment earnings before depreciation, depletion and amortization expenses (defined in the table above and referred to in this report as EBDA) internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our four reportable business segments. Combined, our four business segments reported earnings before depreciation, depletion and amortization of $503.8 million in the first quarter of 2007 and $481.0 million in the first quarter of 2006.

Products Pipelines

	Three Months Ended March 31,
	2007			2006
	(In millions, except operating statistics)
Revenues	$	210.3		$	180.5
Operating expenses		(72.4	)		(60.7	)
Other expense		(0.5	)		—
Earnings from equity investments		7.4			7.9
Interest income and Other, net-income (expense)		1.2			1.2
Income tax expense		(2.8	)		(3.1	)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments	$	143.2		$	125.8

Gasoline (MMBbl)		108.5			111.6
Diesel fuel (MMBbl)		38.8			38.7
Jet fuel (MMBbl)		30.2			29.5
Total refined product volumes (MMBbl)		177.5			179.8
Natural gas liquids (MMBbl)		16.7			16.7
Total delivery volumes (MMBbl)(a)		194.2			196.5

____________

(a)	Includes Pacific, Plantation, North System, CALNEV, Central Florida, Cochin, Cypress and Heartland pipeline volumes.

Following is information related to the increases and decreases, in the first quarter of 2007 compared to the first quarter of 2006, of our Products Pipelines business segment’s (i) earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA); and (ii) operating revenues:

Three months ended March 31, 2007 versus Three months ended March 31, 2006
	EBDA				Revenues
	Increase/(decrease)				increase/(decrease)
	(In millions, except percentages)
North System	$	4.3	83	%	$	3.1		31	%
Cochin pipeline system		4.1	61	%		9.8		86	%
West Coast Terminals		2.3	26	%		1.6		10	%
Transmix operations		2.1	40	%		2.8		38	%
Central Florida Pipeline		2.0	28	%		1.3		13	%
Southeast Terminals		1.6	20	%		4.3		32	%
All others		1.0	1	%		7.0		6	%
Intrasegment Eliminations		—	—			(0.1	)	100	%
Total	$	17.4	14	%	$	29.8		17	%

__________

The overall increase in the segment’s earnings before depreciation, depletion and amortization expenses in the first quarter of 2007, relative to the first quarter of 2006, was driven by the favorable results from our North System common carrier natural gas liquids pipeline, our now 100%-owned Cochin pipeline system, our West Coast and transmix terminal operations, and our Central Florida Pipeline. The period-to-period earnings and revenue increases from the North System were chiefly due to a 29% increase in throughput volumes, mainly attributable to weather related higher propane deliveries and strong refinery feedstock demand. The higher earnings and revenues from the Cochin pipeline system were largely attributable to our January 1, 2007 acquisition of the remaining 50.2% ownership interest that we did not already own. For more information on this acquisition, see Note 2 to our consolidated financial statements included elsewhere in this report.

The period-to-period earnings increase from our West Coast terminal operations was due to both higher operating revenues and lower operating expenses. The 10% increase in revenues was driven by higher throughput revenues from our combined Carson/Los Angeles Harbor terminal system as a result of completed storage and expansion projects since the end of the first quarter of 2006. The decrease in operating expenses in first quarter 2007

versus first quarter 2006, resulted from higher environmental expenses in the first quarter of 2006, associated with environmental liability adjustments made in the first quarter last year.

Earnings before depreciation, depletion and amortization from our petroleum pipeline transmix operations increased 40% in the first quarter of 2007, when compared to last year’s first quarter. The increase mainly resulted from incremental earnings of $1.6 million from our Greensboro, North Carolina facility, and from higher processing revenues from our Colton, California facility, which processes transmix generated from volumes transported to the Southern California and Arizona markets by our Pacific operations’ pipelines. In the second quarter of 2006, we completed construction and placed into service the approximate $11 million Greensboro facility, and it contributed incremental revenues and operating expenses of $1.9 million and $0.3 million, respectively, in the first three months of 2007.

The quarter-over-quarter increase in earnings before depreciation, depletion and amortization from our Central Florida Pipeline system was mainly due to the 13% increase in revenues, attributable to an over 4% increase in transportation volumes and to a mid-year 2006 tariff rate increase. Earnings and revenues increased $1.6 million (20%) and $4.3 million (32%), respectively, from our Southeast terminal operations in the first quarter of 2007 versus the first quarter of 2006. The increase related to higher products volumes and higher terminal blending and storage revenues in the first quarter of 2007, relative to the first quarter last year.

Combining all of the segment’s operations, total delivery volumes of refined petroleum products decreased 1.3% in the first quarter of 2007, compared to the first quarter last year; however, excluding volumes delivered by Plantation, combined deliveries of refined petroleum products were up almost 1% in the first quarter of 2007. In addition, combined mainline delivery and terminal volumes from our Pacific operations increased 1.3% in the first quarter of 2007 versus the first quarter a year ago, with Arizona volumes up 8% due to the completed expansion of our East Line pipeline, which came on-line during the summer of 2006. We expect our Products Pipelines business segment to meet or exceed its budget for 2007.

Natural Gas Pipelines

	Three Months Ended March 31,
	2007			2006
	(In millions, except operating statistics)
Revenues	$	1,535.4		$	1,830.0
Operating expenses		(1,405.7	)		(1,697.8	)
Earnings from equity investments(a)		6.4			11.2
Interest income and Other, net-income (expense)		—			0.4
Income tax expense		(1.4	)		(0.3	)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments	$	134.7		$	143.5

Natural gas transport volumes (Trillion Btus)(b)		378.3			336.7
Natural gas sales volumes (Trillion Btus)(c)		209.0			223.8

__________

(a)	2007 amount includes a $1.0 million increase in expense associated with our portion of a loss from the early extinguishment of debt by Red Cedar Gathering Company.

(b)	Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.

(c)	Represents Texas intrastate natural gas pipeline group.

In the first quarter of 2007, our Natural Gas Pipelines business segment reported an $8.8 million (6%) decrease in earnings before depreciation, depletion and amortization expenses, when compared to the first quarter last year. However, first quarter 2007 earnings included a $1.0 million loss in equity earnings from our 49% interest in the net income of Red Cedar Gathering Company. The loss represented our share of Red Cedar’s approximate $2.0 million loss from the early extinguishment of debt, representing the excess of the price Red Cedar paid to repurchase and retire the principal amount of $31.4 million of its senior notes in March 2007.

Following is information related to the increases and decreases, in the first quarter of 2007 compared to the first quarter of 2006, of our Natural Gas Pipelines business segment’s (i) remaining $7.8 million (5%) decrease in earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA); and (ii) its $294.6 million (16%) decrease in operating revenues:

Three months ended March 31, 2007 versus Three months ended March 31, 2006
	EBDA					Revenues
	increase/(decrease)					increase/(decrease)
	(In millions, except percentages)
Texas Intrastate Natural Gas Pipeline Group	$	(2.4	)	(3	%)	$	(289.5	)	(17	%)
Red Cedar Gathering Company		(1.9	)	(19	%)		—		—
Rocky Mountain Pipeline Group		(1.8	)	(4	%)		4.1		7	%

Casper Douglas gas gathering and processing		(1.1	)	(21	%)		(6.3	)	(25	%)
All others		(0.6	)	(35	%)		(3.4	)	(99	%)
Intrasegment Eliminations		—		—			0.5		67	%
Total	$	(7.8	)	(5	%)	$	(294.6	)	(16	%)

__________

The decrease in earnings in the first quarter of 2007 versus the first quarter of 2006 from our Texas intrastate natural gas pipeline group was due primarily to higher system operating and maintenance expenses and higher income tax expenses. The increase in operating and maintenance expenses, including labor, totaled $1.3 million (12%), and was primarily related to 2006 pipeline integrity projects that were not completed until 2007. The increase in income taxes totaled $1.1 million and was largely due to incremental expense, beginning January 1, 2007, resulting from the new Texas margin tax. The Texas margin tax is a state business tax based on taxable margin, which is determined to be the lowest of (i) 70% of total revenue; (ii) total revenue less costs of goods sold; or (iii) total revenue less compensation and benefits expenses at applicable tax rates of 1% or 0.5%. The Texas margin tax is applicable to virtually all filing entities, including limited partnerships, which do business in the State of Texas.

In general, the variances from period to period in both segment revenues and segment costs of sales are due to lower average gas prices and lower volumes in 2007 versus 2006. In the first quarter of 2007, the net change in our Texas Intrastate group’s revenues and costs of sales were relatively flat, when compared to the first quarter last year, as higher margins from both purchase and sales activities and natural gas processing activities in the first quarter 2007 were largely offset by favorable settlements of pipeline transportation imbalances and higher transportation revenues in the first quarter of 2006.

The quarter-to-quarter 19% decrease in earnings before depreciation, depletion and amortization from the segment’s equity investment in Red Cedar was primarily due to lower income earned by Red Cedar from natural gas gathering and sales of excess fuel gas in the first quarter of 2007, relative to the first quarter last year.

The $1.8 million (4%) decrease in earnings from our Rocky Mountain interstate natural gas pipeline group, which is comprised of Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company, TransColorado Gas Transmission Company, and our current 51% equity investment in the Rockies Express Pipeline, resulted primarily from an incremental $1.7 million decrease in equity earnings from our investment in Rockies Express. The decrease reflects lower net income from Rockies Express, which began interim service in February 2006, due primarily to incremental depreciation and interest expense allocable to a segment of the project that was placed in service in February 2007 and that currently has limited natural gas reservation revenues and volumes.

On February 14, 2007, we began service on the second segment of the first leg of the Rockies Express Pipeline, a 191-mile section of 42-inch diameter pipeline that extends from the Wamsutter Hub in Sweetwater County, Wyoming to the Cheyenne Hub in Weld County, Colorado. Approximately 328 miles of the project, which originates at the Meeker Hub in Rio Blanco County, Colorado, are now in service, transporting up to 500 million cubic feet of natural gas per day. Earnings before depreciation, depletion and amortization from our Casper Douglas processing operations decreased 21% in the first quarter of 2007, when compared to the first quarter of 2006. The drop in Casper Douglas’ earnings was primarily due to the sale of our Douglas natural gas gathering system to a

third party effective April 1, 2006. We expect our Natural Gas Pipelines business segment to meet or exceed its budget for 2007.

CO₂

	Three Months Ended March 31,
	2007			2006
	(In millions, except operating statistics)
Revenues	$	191.6		$	174.7
Operating expenses		(70.6	)		(58.5	)
Earnings from equity investments		5.2			5.6
Other, net-income (expense)		—			—
Income tax expense		(0.8	)		(0.1	)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments	$	125.4		$	121.7

Carbon dioxide delivery volumes (Bcf)(a)		165.7			172.4
SACROC oil production (gross)(MBbl/d)(b)		29.9			31.3
SACROC oil production (net)(MBbl/d)(c)		24.9			26.1
Yates oil production (gross)(MBbl/d)(b)		26.1			25.0
Yates oil production (net)(MBbl/d)(c)		11.6			11.1
Natural gas liquids sales volumes (net)(MBbl/d)(c)		9.7			9.3
Realized weighted average oil price per Bbl(d)(e)	$	35.17		$	30.47
Realized weighted average natural gas liquids price per Bbl(e)(f)	$	41.71		$	41.35

__________

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

(b) 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.

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

(d)	Includes all Kinder Morgan crude oil production properties.

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

(f) 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.

For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the first quarter of 2007 compared to the first quarter of 2006, of (i) earnings before depreciation, depletion and amortization (EBDA); and (ii) operating revenues:

Three months ended March 31, 2007 versus Three months ended March 31, 2006
	EBDA increase/(decrease)					Revenues increase/(decrease)
	(In millions, except percentages)
Sales and Transportation Activities	$	(2.7	)	(6	%)	$	(1.6	)	(4	%)
Oil and Gas Producing Activities		6.4		8	%		16.4		11	%
Intrasegment Eliminations		—		—			2.1		15	%
Total	$	3.7		3	%	$	16.9		10	%

__________

The period-to-period growth in earnings before depreciation, depletion and amortization expenses from the segment’s oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants, was largely revenue related, driven by higher revenues from the sale of crude oil and natural gas plant liquids products.

Revenues from crude oil sales and natural gas plant products sales increased $14.2 million (14%) and $2.0 million (6%), respectively, in the first quarter of 2007 compared to the first quarter of 2006. With regard to crude oil, a slight (1%) overall decrease in volumes was more than offset by a 15% increase in our realized weighted average price per barrel; with regard to natural gas liquids, we benefited from an over 4% increase in sales volumes and a 1% increase in our realized weighted average price per barrel.

Because our CO₂ segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, we mitigate this risk through a long-term hedging strategy that involves the use of derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $55.52 per barrel in the first quarter of 2007, and $60.62 per barrel in the first quarter of 2006. 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 10 to our consolidated financial statements included elsewhere in this report.

The quarter-to-quarter $2.7 million (6%) decrease in earnings before depreciation, depletion and amortization from the segment’s sales and transportation activities was primarily due to a decrease in carbon dioxide sales revenues, partially offset by an increase in pipeline transportation revenues. The decrease in carbon dioxide sales revenues was due to a 14% drop in average carbon dioxide sale prices in the first quarter of 2007, reflecting higher price levels a year ago that were boosted, in part, by higher average crude oil prices. The unfavorable price variance more than offset an over 2% increase in sales volumes driven by increased carbon dioxide production from the McElmo Dome source field and as always, we do not recognize profits on carbon dioxide sales to ourselves. The increase in pipeline transportation revenues was driven by higher crude oil transportation volumes from our Kinder Morgan Wink Pipeline.

Compared to the first quarter of 2006, the segment’s operating expenses increased $12.1 million (21%) in the first quarter of 2007. The increase was largely due to additional labor and field expenses, driven by higher well workover and completion expenses related to infrastructure expansions at the SACROC and Yates oil field units, and to higher fuel and power expenses. In addition, segment income tax expenses increased $0.7 million (700%) in the first quarter of 2007, when compared to the first quarter a year ago. The increase was largely due to incremental expense, beginning January 1, 2007, resulting from the new Texas margin tax described above in “—Natural Gas Pipelines.” As of March 31, 2007, we expect our CO₂ business segment to fall short of its budget for 2007.

Terminals

	Three Months Ended March 31,
		2007			2006
	(In millions, except operating statistics)
Revenues		$	215.1		$	206.4
Operating expenses			(115.8	)		(115.8	)
Other income(a)			2.7			—
Earnings from equity investments			—			—
Other, net-income (expense)			—			1.4
Income tax expense			(1.5	)		(2.0	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	100.5		$	90.0

Bulk transload tonnage (MMtons)(b)			19.6			21.2
Liquids leaseable capacity (MMBbl)			43.6			42.8
Liquids utilization %			98.5	%		97.8	%

__________

(a) 2007 amount includes an increase in income of $1.8 million from property casualty gains associated with the 2005 Hurricane season.

(b)	Volumes for acquired terminals are included for both periods.

Our Terminals business 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. In the first quarter of 2007, the segment’s overall $10.5 million (12%) increase in earnings before depreciation, depletion and amortization compared to the year earlier first quarter included a $1.8 million gain, recognized in January 2007, based upon our final determination of the book value of fixed assets damaged or destroyed during Hurricanes Katrina and Rita in 2005.

Our Terminals segment’s remaining $8.7 million (10%) increase in earnings before depreciation, depletion and amortization expenses in the first quarter of 2007 compared with the first quarter of 2006 was due to a combination of internal expansions and strategic acquisitions, but offset partially by decreases in earnings from terminals included in our Texas Petcoke and Mid-Atlantic regions that were owned during the first quarter of both years (discussed below).

We make and continue to seek key terminal acquisitions in order to gain access to new markets and to complement and/or enlarge our existing terminal operations. Since the end of the first quarter of 2006, we have invested approximately $82.7 million in cash and $1.7 million in common units to acquire terminal assets and combined, these operations accounted for incremental amounts of earnings before depreciation, depletion and amortization of $5.5 million, revenues of $14.0 million and operating expenses of $8.5 million, respectively, in 2007. Our significant terminal acquisitions since the end of the first quarter of 2006 included the following:

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

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

For all other terminal operations (those owned during the first three months of both comparable years), earnings before depreciation, depletion and amortization expenses and the property casualty gain increased $3.2 million (4%) and revenues decreased $5.3 million (3%) in the first quarter of 2007, when compared to last year’s first quarter.

Following is information, by terminal operating region, related to these quarter-to-quarter changes:

Three months ended March 31, 2007 versus Three months ended March 31, 2006
	EBDA increase/(decrease)		Revenues increase/(decrease)
	(In millions, except percentages)
Gulf Coast	$3.2	16%	$3.1	10%
Northeast	2.3	17%	1.1	4%
Midwest	1.7	16%	1.3	5%
Lower Mississippi (Louisiana)	1.0	14%	(2.7)	(8%)
Texas Petcoke	(2.1)	(16%)	(3.3)	(13%)
Mid-Atlantic	(1.9)	(18%)	(4.9)	(18%)
All others	(1.0)	(7%)	0.2	—
Intrasegment Eliminations	—	—	(0.1)	(25%)
Total	$3.2	4%	$(5.3)	(3%)

__________

The increase in earnings before depreciation, depletion and amortization expenses in the first quarter of 2007 compared with the first quarter of 2006 from our Gulf Coast region was driven by favorable results from our Pasadena and Galena Park, Texas liquids facilities located along the Houston Ship Channel. The increase from our Pasadena terminal was driven by higher revenues from incremental customer agreements, higher refinery throughput and transmix sales, and higher truck loading rack service fees. The increase at Galena Park was due to both higher revenues and lower operating expenses. The increase in revenues was due to additional tankage available for lease and higher refinery throughput; the decrease in operating expenses was largely related to higher environmental expenses, recorded in the first quarter of 2006, associated with environmental liability accrual adjustments.

The increase in earnings from our Northeast terminals was primarily due to higher earnings from our liquids terminal facilities located in Perth Amboy and Carteret, New Jersey. For the two terminals combined, the earnings increase was largely due to higher revenues from new and renegotiated customer contracts, ancillary services and an overall 30% increase in fuel grade ethanol volumes.

We also benefited from higher earnings before depreciation, depletion and amortization in the first quarter of 2007, relative to the prior year, from terminal operations included in our Midwest and Louisiana regions. The increase from our Midwest terminals 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 quarter-to-quarter increase in earnings from the two liquids terminals was primarily due to higher revenues, due to increased ethanol throughput and incremental liquids storage and handling business. The increase in earnings at Cora was mainly attributable to higher revenues resulting from a 13% increase in coal transfer volumes in the first quarter of 2007. For our Louisiana terminals, the increase in earnings before depreciation, depletion and amortization in the first quarter of 2007, versus the first quarter last year, was largely related to the negative effects of the two Gulf Coast hurricanes in 2005, resulting in an overall general loss of business in the first quarter of 2006.

Partially offsetting the segment’s overall growth in earnings before depreciation, depletion and amortization in the first quarter of 2007 compared with the first quarter of 2006 were lower earnings from terminal activity in our Texas Petcoke and Mid-Atlantic regions. The decrease from our Texas petroleum coke operations was due mainly to lower quarter-over-quarter revenues, due to both a 16% drop in petroleum coke volumes, largely related to a refinery shutdown in the first quarter of 2007, and to unfavorable true-ups and adjustments, recognized in the first quarter of 2007, to certain prior period estimates. The decrease from our Mid-Atlantic region was driven by lower earnings from our Fairless Hills, Pennsylvania bulk terminal, primarily due to a significant down-turn in steel imports in the first quarter of 2007 versus the first quarter of 2006. We expect our Terminals business segment to meet or exceed its budget for 2007.

Other

	Three Months Ended March 31,						Earnings
	2007			2006				increase/(decrease)
	(In millions-income (expense), except percentages)
General and administrative expenses(a)	$	(65.8	)	$	(60.9	)		$	(4.9	)	(8	%)
Unallocable interest expense, net of interest income		(91.1	)		(76.9	)			(14.2	)	(18	%)
Minority interest(b)		(2.6	)		(2.4	)			(0.2	)	(8	%)
Total interest and corporate administrative expenses	$	(159.5	)	$	(140.2	)		$	(19.3	)	(14	%)

__________

(a)	2007 amount includes an increase in expense of $1.7 million related to incremental hurricane insurance premiums.

(b)	2007 amount includes an expense of $0.5 million 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. 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.

The $4.9 million (8%) increase in total general and administrative expenses in the first quarter of 2007 versus the first quarter of 2006 was primarily due to higher property and corporate insurance expenses, higher legal expenses and higher payroll expense. The period-to-period increase in insurance expenses was largely related to a one-time assessment on an insurance policy that we no longer have, and to increased hurricane insurance coverage at higher rates (in the first quarter of 2007, we recognized an incremental expense of $1.7 million for additional hurricane insurance premium expenses). The increase in legal expenses was mostly due to incremental legal invoices and charges from outside attorneys, and the increases in salary and corporate labor charges were primarily due to increased hiring since the first quarter of last year.

Unallocable interest expense, net of interest income, increased $14.2 million (18%) in the first quarter of 2007, compared to the same year-earlier period. The increase was due to both an 8% increase in the weighted average interest rate on all of our borrowings and an 8% increase in average borrowings. The increase in our average borrowing rate reflects a general rise in variable interest rates since the end of the first quarter of 2006, and the increase in average debt levels was largely due to expansion capital expenditures and to terminal acquisitions made since the end of the first quarter of 2006.

Additionally, on January 30, 2007, 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 net proceeds from the issuance of the notes, after underwriting discounts and commissions, of approximately $992.8 million, and we used the net proceeds to reduce the borrowings under our commercial paper program. We issue senior notes in order to refinance commercial paper borrowings used for both internal capital spending and acquisition expenditures.

Financial Condition

Capital Structure

We attempt to maintain a conservative overall capital structure, with a long-term target mix of approximately 50% equity and 50% debt. In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”

The following table illustrates the sources of our invested capital (dollars in millions):

	March 31, 2007			December 31, 2006
Long-term debt, excluding value of interest rate swaps	$	5,415.0		$	4,384.3
Minority interest		48.9			50.6
Partners’ capital, excluding accumulated other comprehensive loss		4,818.6			4,863.3
Total capitalization		10,282.5			9,298.2
Short-term debt, less cash and cash equivalents		603.2			1,345.1
Total invested capital	$	10,885.7		$	10,643.3

Capitalization:
Long-term debt, excluding value of interest rate swaps		52.6	%		47.2	%
Minority interest		0.5	%		0.5	%
Partners’ capital, excluding accumulated other comprehensive loss		46.9	%		52.3	%
		100.0	%		100.0	%

Invested Capital:
Total debt, less cash and cash equivalents and excluding
value of interest rate swaps		55.3	%		53.8	%
Partners’ capital and minority interest, excluding accumulated other comprehensive loss		44.7	%		46.2	%
		100.0	%		100.0	%

Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements for expansion capital expenditures through borrowings under our credit facility, issuing short-term commercial paper, long-term notes or additional common units or the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares. Further information on our financing strategies and activities can be found in our Annual Report on Form 10-K for the year ended December 31, 2006.

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 finalizes its ratings for KMI; however, at this time, Moody’s has not changed their ratings on KMI or us. Additionally, our rating was downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007. We are not able to predict with certainty the final affect of the pending buyout proposal on our credit ratings.

Short-term Liquidity

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

Borrowings under our credit facility can be used for general corporate purposes and as a backup for our commercial paper program. The facility can be amended to allow for borrowings up to $2.1 billion. There were no borrowings under our credit facility as of March 31, 2007, or as of December 31, 2006. As of March 31, 2007, we had $354.3 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 $1,110.0 million as of March 31, 2007. As of March 31, 2007, our outstanding short-term debt was $624.7 million. Currently, we believe our liquidity to be adequate.

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 are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows.

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 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.

As of March 31, 2007, our total liability balance due on the various series of our senior notes was $5,489.6 million, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries

was $195.9 million. For additional information regarding our debt securities and credit facility, see Note 9 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2006.

Operating Activities

Net cash provided by operating activities was $315.2 million for the three months ended March 31, 2007, versus $176.0 million in the comparable period of 2006. The period-to-period increase of $139.2 million (79%) in cash flow from operations principally consisted of:

a $70.3 million (52%) increase in cash inflows relative to net changes in working capital items, mainly due to timing differences that resulted in higher net cash inflows of $95.1 million with regard to the collection and payment of both trade and related party receivables and payables;

a $25.6 million (97%) increase in cash inflows relative to net changes in non-current assets and liabilities—related to, among other things, higher payments made in the first quarter of 2006 for pipeline project costs, studies and business development charges, largely related to the Rockies Express Pipeline, and for higher payments made for natural gas liquids inventory on our North System. In the second quarter of 2006, we transferred accumulated project costs related to the Rockies Express to “Property, plant and equipment, net” on our consolidated balance sheet;

a $21.7 million (97%) increase related to higher distributions received from equity investments—chiefly due to a $32.6 million distribution received from Red Cedar Gathering Company in March 2007 following a refinancing of its long-term debt obligations. In the first quarter of 2007, Red Cedar used the proceeds received from the sale of unsecured senior notes to refund and retire the outstanding balance on its then-existing senior notes, and to make a distribution to its two owners; and

a $15.0 million increase in cash from an interest rate swap termination payment we received in March 2007, when we terminated a fixed-to-floating interest rate swap agreement having a notional principal amount of $100 million and a maturity date of March 15, 2032.

Investing Activities

Net cash used in investing activities was $275.7 million for the three month period ended March 31, 2007, compared to $479.9 million in the comparable prior year period. The $204.2 million (43%) decrease in cash used in investing activities was primarily attributable to:

a $236.1 million (98%) decrease due to lower expenditures made for strategic business acquisitions—in the first quarter of 2007, our acquisition outlays totaled $3.9 million, primarily consisting of cash paid for the remaining 50.2% ownership interest in the Cochin pipeline system that we did not already own; in the first quarter of 2006, we spent $240.0 million to acquire all of the ownership interests in Entrega Gas Pipeline LLC; and

a $51.8 million (27%) increase in capital expenditures—largely due to increased investment undertaken to expand and improve our bulk and liquids terminalling operations. Our sustaining capital expenditures, defined as capital expenditures which do not increase the capacity of an asset, were $26.8 million for the first three months of 2007, compared to $25.7 million for the first three months of 2006. Our forecasted expenditures for the remaining nine months of 2007 for sustaining capital expenditures are approximately $127.0 million. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary.

In addition, we recently made the following three announcements related to our investing activities:

On February 28, 2007, we announced plans to invest up to $100 million to expand our terminal facilities in order to help serve the growing biodiesel market. We entered into long-term agreements with Green Earth Fuels, LLC to build up to 1.3 million barrels of tankage that will handle approximately eight million barrels of biodiesel production at certain of our terminal facilities located on the Houston Ship Channel, the Port of

New Orleans and in New York Harbor. Green Earth Fuels has already begun construction on an 86 million gallon biodiesel tank facility at our Galena Park, Texas liquids terminal located on the Houston Ship Channel, and the biodiesel facility is expected to commence operations in July 2007;

On April 18, 2007, we announced that we had entered into a long-term agreement with a consortium of airlines to construct a 9-mile, 8-inch diameter pipeline and related storage facilities to connect Tampa International Airport with our Tampa, Florida refined products terminal. We will invest approximately $25 million to build the new pipeline that will be capable of transporting more than 30,000 barrels per day of jet fuel and a new storage tank that will increase storage capacity at the terminal by approximately 386,000 barrels (45%). The entire project is expected to be fully completed and in service in the fourth quarter of 2008; and

On April 18, 2007, we announced that we will invest approximately $29 million to construct our Colorado Lateral expansion project, which includes a 38-mile pipeline that will transport natural gas from the Cheyenne Hub to various delivery points in Greeley, Colorado. The pipeline will have an initial capacity of 74 million cubic feet per day, and firm-contracted service is expected to begin in the third quarter of 2008.

Also, in August 2007, KMIGT intends to file a prior notice request with the FERC for authorization to construct and operate certain mainline looping pipeline facilities near the existing Grand Island, Nebraska compressor station necessary to provide firm transportation service to four ethanol plants and one industrial sand plant, all located in the State of Nebraska. Such facilities are currently estimated to cost approximately $24.5 million and will increase the capacity of KMIGT’s pipeline by approximately 34 million cubic feet of natural gas per day.

Financing Activities

Net cash used in financing activities amounted to $32.1 million for the first three months of 2007. For the same three month period last year, our financing activities provided net cash of $324.4 million. The $356.5 million decrease from the comparable 2006 period was primarily due to:

a $235.4 million decrease from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The decrease was primarily due to a $1,229.0 million decrease in cash from lower net commercial paper borrowings in the first quarter of 2007, relative to the first quarter of 2006, partially offset by a $992.8 million increase in cash inflows from our public offering of senior notes in January 2007;

a $90.5 million decrease from contributions from minority interests—principally due to Sempra Energy’s $80.0 million contribution for its 33 1/3% share of the purchase price of Entrega Gas Pipeline LLC, discussed above in “—Investing Activities;” and

a $28.0 million decrease from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet endorsed.

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. Our Annual Report on Form 10-K for the year ended December 31, 2006 contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including minority interests.

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 in February 2006 for the fourth quarter of 2005. We paid this distribution in cash to our general partner and to our common and Class B unitholders. Total cash distributions to all partners, including minority interests, totaled $264.2 million in the first quarter of 2007, compared to $261.0 million in the comparable 2006 period. 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.

Additionally, on April 18, 2007, we declared a cash distribution of $0.83 per unit for the first quarter of 2007 (an annualized rate of $3.32 per unit). This distribution was 2% higher than the $0.81 per unit distribution we made for the first quarter of 2006. 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 projection does not include any benefits from unidentified acquisitions or take into account any capital costs associated with financing the payment of reparations sought by shippers on our Pacific operations’ interstate pipelines.

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. 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. Under the terms of our partnership agreement, our distribution of $0.83 per unit paid on February 14, 2007 for the fourth quarter of 2006 required an incentive distribution to our general partner of $138.1 million; however, according to the provisions of the KMI Annual Incentive Plan, in order for the executive officers of our general partner and KMR, and for the employees of KMGP Services Company, Inc. and KMI who operate our business to earn a non-equity cash incentive (bonus) for 2006, both we and KMI were required to meet pre-established financial performance targets. The target for us was $3.28 in cash distributions per common unit for 2006, and due to the fact that we did not meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan.

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 incentive distribution for the fourth quarter of 2006. The waiver approximated an amount equal to our actual bonus payout for 2006, and including the effect of this waiver, our distribution to unitholders for the fourth quarter of 2006 resulted in an incentive distribution to our general partner in the amount of $118.0 million.

Our general partner’s incentive distribution that we paid in February 2006 to our general partner (for the fourth quarter of 2005) was $125.6 million. Our general partner’s incentive distribution for the distribution that we declared for the first quarter of 2007 was $138.8 million, and our general partner’s incentive distribution for the distribution that we paid for the first quarter of 2006 was $128.3 million. The period-to-period increases in our general partner incentive distributions resulted from both increased cash distributions per unit and increases in the number of common units and i-units outstanding.

Litigation and Environmental

As of March 31, 2007, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $58.1 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 March 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $109.9 million. The reserve is primarily related to various claims from lawsuits arising from SFPP, L.P.’s 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.

We believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, changing circumstances could cause these matters to have a material adverse impact.

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

Please refer to Notes 3 and 14, respectively, to our consolidated financial statements included elsewhere in this report for additional information regarding pending litigation, environmental and asset integrity matters.

Certain Contractual Obligations

There have been no material changes in our contractual obligations that would affect the disclosures presented as of December 31, 2006 in our 2006 Form 10-K report.

Off Balance Sheet Arrangements

Except as set forth under “—Red Cedar Gathering Company Debt” in Note 7 to our consolidated financial statements included elsewhere in this report, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2006 in our 2006 Form 10-K.

Information Regarding Forward-Looking Statements

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

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

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

changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;

our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to make expansions to our facilities;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

our ability to successfully identify and close acquisitions and make cost-saving changes in operations;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;

crude oil and natural gas production from exploration and production areas that we serve, 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 our business or our ability to compete;

changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;

our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;

our ability to obtain insurance coverage without significant levels of self-retention of risk;

acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits;

capital 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 to achieve cost savings and revenue growth;

inflation;

interest rates;

the pace of deregulation of retail natural gas and electricity;

foreign exchange fluctuations;

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

the extent of our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;

the uncertainty inherent in estimating future oil and natural gas production or reserves;

the ability to complete expansion projects on time and on budget;

the timing and success of business development efforts; and

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” of our Annual Report on Form 10-K for the year ended December 31, 2006, 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 our 2006 Form 10-K report. 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 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2006, in Item 7A of our 2006 Form 10-K report. For more information on our risk management activities, see Note 10 to our consolidated financial statements included elsewhere in this report.

Item 4. Controls and Procedures.

As of March 31, 2007, 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 in all material respects 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. There has been no change in our internal control over financial reporting during the quarter ended March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I, Item 1, Note 3 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes to the risk factors disclosed in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

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

None.

Item 5. Other Information.

None.

Item 6. Exhibits.

4.1 --	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.

4.2 --	Certificate of the President and the Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037.

11 --	Statement re: computation of per share earnings.

12 --	Statement re: computation of ratio of earnings to fixed charges.

31.1 --	Certification by CEO pursuant to Rule 13a-14 or 15d-14 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 or 15d-14 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.

__________

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	KINDER MORGAN ENERGY PARTNERS, L.P.
	(A Delaware limited partnership)

	By:	KINDER MORGAN G.P., INC.,
		its sole General Partner

	By:	KINDER MORGAN MANAGEMENT, LLC,
		the Delegate of Kinder Morgan G.P., Inc.

		/s/ Kimberly A. Dang
		Kimberly A. Dang
		Vice President and Chief Financial Officer
		(principal financial and accounting officer)
		Date: May 8, 2007

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Kinder Morgan Energy Partners L P 10-Q2007 Q1 Quarterly report

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