8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  September 18, 2009

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)

Kansas (State or other jurisdiction of incorporation) 1-06446 (Commission File Number) 48-0290000 (I.R.S. Employer Identification No.)

500 Dallas Street, Suite 1000

Houston, Texas 77002

(Address of principal executive offices, including zip code)

713-369-9000

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Items

On January 1, 2009, we adopted the provisions of Financial Accounting Standards Board Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment to ARB No. 51 (“SFAS No. 160”). Based on the effective date of the pronouncement, the audited consolidated financial statements in the Kinder Morgan, Inc. Annual Report on Form 10-K for the year ended December 31, 2008 (“Form 10-K”) did not reflect the adoption of SFAS No. 160. Accordingly, the following sections of our Form 10-K have been updated solely to reflect the retrospective presentation and disclosure requirements of SFAS No. 160 that were not yet effective for the financial statements originally filed with our Form 10-K, and are filed herewith as Exhibit 99.1 and incorporated herein by reference:

· Item 6. Selected Financial Data

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

· Item 8. Financial Statements and Supplementary Data

In addition, on July 15, 2009, Knight Inc. changed its name to Kinder Morgan, Inc. References in the Form 10-K sections identified above to Knight Inc. have been replaced with Kinder Morgan, Inc.

No Items of the Form 10-K other than those identified above are being adjusted or otherwise revised by this filing.

This Current Report on Form 8-K should be read in conjunction with the Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 and other filings with the Securities and Exchange Commission. Information in the Form 10-K is generally stated as of December 31, 2008, and this filing does not reflect any subsequent information or events other than the adoption of the presentation and disclosure requirements of SFAS No. 160 and the name change described above. More current information is contained in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 and other filings with the Securities and Exchange Commission.

Item 9.01.  Financial Statements and Exhibits.

(d)	Exhibits.
	99.1	Selected Items of the Kinder Morgan, Inc (formerly Knight Inc.) Annual Report on Form 10-K for the year ended December 31, 2008, as revised.

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S I G N A T U R E

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 hereunto duly authorized.

	KINDER MORGAN, INC.
Dated: September 18, 2009	By:	/s/ Kimberly A. Dang
		Kimberly A. Dang Vice President and Chief Financial Officer

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Index to Exhibits

Exhibit No.	Description
99.1	Selected Items of the Kinder Morgan, Inc. (formerly Knight Inc.) Annual Report on Form 10-K for the year ended December 31, 2008, as revised.

EX-99.1

Exhibit 99.1

PART II

Item 6. Selected Financial Data.

Five-Year Review

Kinder Morgan, Inc. and Subsidiaries

	Successor Company						Predecessor Company
	Year Ended December 31,			Seven Months Ended December 31,			Five Months Ended May 31,			Year Ended December 31,
	20081,2			20071,2			20072,3			20062,3			20053			2004
	(In millions)						(In millions)
Operating Revenues	$	12,094.8		$	6,394.7		$	4,165.1		$	10,208.6		$	1,025.6		$	877.7
Gas Purchases and Other Costs of Sales		7,744.0			3,656.6			2,490.4			6,339.4			302.6			194.2
Other Operating Expenses4,5,6		6,822.9			1,695.3			1,469.9			2,124.0			341.7			342.5
Operating Income (Loss)		(2,472.1	)		1,042.8			204.8			1,745.2			381.3			341.0
Other Income and (Expenses)		(425.9	)		(529.3	)		(211.3	)		(484.7	)		520.5			421.6
Income (Loss) from Continuing Operations Before Income Taxes		(2,898.0	)		513.5			(6.5	)		1,260.5			901.8			762.6
Income Taxes		304.3			227.4			135.5			285.9			337.1			208.0
Income (Loss) from Continuing Operations		(3,202.3	)		286.1			(142.0	)		974.6			564.7			554.6
Income (Loss) from Discontinued Operations, Net of Tax7		(0.9	)		(1.5	)		298.6			(528.5	)		40.4			23.9
Net Income (Loss)		(3,203.2	)		284.6			156.6			446.1			605.1			578.5
Net Income Attributable to Noncontrolling Interests8		(396.1	)		(37.6	)		(90.7	)		(374.2	)		(50.5	)		(56.4	)
Net Income (Loss) Attributable to Kinder
Morgan, Inc.’s Stockholder(s)	$	(3,599.3	)	$	247.0		$	65.9		$	71.9		$	554.6		$	522.1
Capital Expenditures9	$	2,545.3		$	1,287.0		$	652.8		$	1,375.6		$	134.1		$	103.2

__________

1 Includes significant impacts resulting from the Going Private transaction. See Note 1 of the accompanying Notes to Consolidated Financial Statements for additional information.

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

3 Includes the results of Terasen Inc. subsequent to its November 30, 2005 acquisition by us. See Notes 10 and 11 of the accompanying Notes to Consolidated Financial Statements for information regarding Terasen.

4 Includes non-cash goodwill charges of $4,033.3 million in the year ended December 31, 2008.

5 Includes charges of $1.2 million, $6.5 million and $33.5 million in 2006, 2005 and 2004, respectively, to reduce the carrying value of certain power assets.

6 Includes an impairment charge of $377.1 million in the five months ended May 31, 2007 relating to Kinder Morgan Energy Partners’ acquisition of Trans Mountain pipeline from us on April 30, 2007. See Note 3 of the accompanying Notes to Consolidated Financial Statements.

7 Includes a charge of $650.5 million in 2006 to reduce the carrying value of Terasen Inc.; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

8 Includes application of SFAS No. 160, Noncontolling Interest in Consolidated Financial Statements, for all periods presented. See Note 1 of the accompanying Notes to Consolidated Financial Statements.

9 Capital expenditures shown are for continuing operations only.

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	As of December 31,
	Successor Company								Predecessor Company
	2008				20071				20062				20053				2004
	(In millions, except percentages)								(In millions, except percentages)
Total Assets	$	25,444.9			$	36,101.0			$	26,795.6			$	17,451.6			$	10,116.9
Capitalization:
Kinder Morgan, Inc. Stockholder’s Equity4	$	4,457.7	23	%	$	8,069.2	30	%	$	3,657.5	20	%	$	4,051.4	34	%	$	2,919.5	45	%
Noncontrolling Interests		4,072.6	21	%		3,314.0	13	%		3,095.5	17	%		1,247.3	10	%		1,105.4	17	%
Total Stockholders' Equity		8,530.3	44	%		11,383.2	33	%		6,753	37	%		5,298.7	44	%		4,024.9	62	%
Deferrable Interest Debentures		35.7	-			283.1	1	%		283.6	2	%		283.6	2	%		283.6	4	%
Capital Securities		-	-			-	-			106.9	1	%		107.2	1	%		-	-
Outstanding Notes and Debentures5		11,120.1	56	%		14,814.6	56	%		10,623.9	60	%		6,286.8	53	%		2,258.0	34	%
Total Capitalization	$	19,686.1	100	%	$	26,480.9	100	%	$	17,767.4	100	%	$	11,976.3	100	%	$	6,566.5	100	%

__________

1 Includes significant impacts resulting from the Going Private transaction. See Note 1 of the accompanying Notes to Consolidated Financial Statements for additional information.

2 Due to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts, balances and results of operations of Kinder Morgan Energy Partners are included in our financial statements and we no longer apply the equity method of accounting to our investments in Kinder Morgan Energy Partners.

3 Reflects the acquisition of Terasen Inc. on November 30, 2005. See Notes 10 and 11 of the accompanying Notes to Consolidated Financial Statements for information regarding this acquisition.

4 Kinder Morgan, Inc. stockholder’s equity excluding Accumulated Other Comprehensive Loss balances of $53.4 million, $247.7 million, $135.9 million, $127.0 million, and $54.7 million as of December 31, 2008, 2007, 2006, 2005, and 2004, respectively.

5 Excluding the value of interest rate swaps and short-term debt. See Note 14 of the accompanying Notes to Consolidated Financial Statements.

 

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

General

The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related Notes.

We are an energy infrastructure provider through our direct ownership and operation of energy related assets, and through our ownership interests in and operation of Kinder Morgan Energy Partners. Our strategy and focus are on ownership of fee-based energy-related assets which are core to the energy infrastructure of North America and serve growing markets. These assets tend to have relatively stable cash flows while presenting us with opportunities to expand our facilities to serve additional customers and nearby markets. We evaluate the performance of our investment in these assets using, among other measures, segment earnings before depreciation, depletion and amortization.

Our principal business segments are:

· Natural Gas Pipeline Company of America LLC—which consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system which we operate;

· Power—which consists of two natural gas-fired electric generation facilities;

· Products Pipelines–KMP—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;

· Natural Gas Pipelines–KMP—which consists of over 14,300 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

· CO2–KMP—which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;

· Terminals–KMP—which consists of approximately 110 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and

· Kinder Morgan Canada–KMP—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington state; plus five associated product terminals. This segment also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.

As an energy infrastructure owner and operator in multiple facets of the United States’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future. The profitability of our products pipeline transportation business is generally driven by the utilization of our facilities in relation to their capacity, as well as the prices we receive for our services. Transportation volume levels are primarily driven by the demand for the petroleum products being shipped or stored. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the Producer Price Index. Because of the overall effect of utilization on our products pipeline transportation business, we seek to own refined products pipelines located in or that transport to stable or growing markets and population centers.

With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets tend to be received under contracts with terms that are fixed for various periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. However, changes, either positive or negative, in actual quantities transported on our interstate natural gas pipelines may not accurately measure or predict associated changes in profitability because many of the underlying transportation contracts, sometimes referred to as take-or-pay contracts, specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.

The CO2–KMP business segment sales and transportation business, like the natural gas pipelines business, generally has take-or-pay contracts, although the contracts in the CO2–KMP business segment typically have minimum volume requirements. In

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the long term, the success in this business is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum volumes under many of our contracts. In the oil and gas producing activities within the CO2–KMP business segment, we monitor the amount of capital we expend in relation to the amount of production that is added or the amount of declines in production that are postponed. In that regard, our production during any period and the reserves that we add during that period are important measures. In addition, the revenues we receive from our crude oil, natural gas liquids and CO2 sales are affected by the prices we realize from the sale of these products. Over the long term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, published market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivatives, particularly for oil.

As with our products pipeline transportation businesses, the profitability of our terminals businesses is generally driven by the utilization of our terminals facilities in relation to their capacity, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. The extent to which changes in these variables affect this business in the near term is a function of the length of the underlying service contracts, the extent to which revenues under the contracts are a function of the amount of product stored or transported and the extent to which such contracts expire during any given period of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related factors such as hurricanes, floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

In our discussions of the operating results of individual businesses that follow, we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods. Principally through Kinder Morgan Energy Partners, we have a history of making accretive acquisitions and economically advantageous expansions of existing businesses. Our ability to increase earnings and Kinder Morgan Energy Partners’ ability to increase distributions to us and other investors will, to some extent, be a function of Kinder Morgan Energy Partners’ success in acquisitions and expansions. Kinder Morgan Energy Partners continues to have opportunities for expansion of its facilities in many markets and expects to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict.

Kinder Morgan Energy Partners’ ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates and, to some extent, its ability to raise necessary capital to fund such acquisitions, factors over which it has limited or no control. Thus, it has no way to determine the extent to which it will be able to identify accretive acquisition candidates, or the number or size of such candidates, in the future, or whether it will complete the acquisition of any such candidates.

On November 24, 2008, Kinder Morgan Energy Partners announced that it expected to declare 2009 cash distributions of $4.20 per unit, a 4.5% increase over its 2008 cash distributions of $4.02 per unit. The expected growth in 2009 distributions assumes an average West Texas Intermediate crude oil price of $68 per barrel in 2009 with some minor adjustments for timing, quality and location differences. Based on actual prices received through the first seven weeks of 2009 and the forward curve, adjusted for the same factors as the budget, the average realized price for 2009 is currently projected to be $49 per barrel. Although the majority of the cash generated by Kinder Morgan Energy Partners’ assets is fee based and is not sensitive to commodity prices, the CO2–KMP business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids. Kinder Morgan Energy Partners hedges the majority of its crude oil production, but does have exposure to unhedged volumes, the majority of which are natural gas liquids volumes. For 2009, Kinder Morgan Energy Partners expects that every $1 change in the average WTI crude oil price per barrel will impact its CO2–KMP segment’s cash flows by approximately $6 million (or approximately 0.2% of the combined Kinder Morgan Energy Partners business segments’ anticipated distributable cash flow). This sensitivity to the average WTI price is very similar to what was experienced in 2008. Kinder Morgan Energy Partners’ 2009 cash distribution expectations do not take into account any capital costs associated with financing any payment it may be required to make of reparations sought by shippers on its Pacific operations’ interstate pipelines.

In light of the above and other economic uncertainties we are taking cost reduction measures for 2009. We are reducing our travel costs and compensation costs, decreasing the use of outside consultants, reducing overtime where possible and reviewing capital and operating budgets to identify the costs we can reduce without compromising operating efficiency, maintenance or safety.

In addition to any uncertainties described in this discussion and analysis, we are subject to a variety of risks that could have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Risk Factors” in Item 1A.

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During 2006 and 2007, we reached agreements to sell certain businesses and assets in which we no longer have any continuing interest, including Terasen Gas, Corridor, the North System and our Kinder Morgan Retail segment. Accordingly, the activities and assets related to these sales are presented as discontinued items in the accompanying Consolidated Financial Statements. As discussed following, many of our operations are regulated by various federal and state regulatory bodies.

In February 2007, we entered into a definitive agreement to sell our Canada-based retail natural gas distribution operations to Fortis Inc., for approximately C$3.7 billion including cash and assumed debt, and as a result of a redetermination of fair value in light of this proposed sale, we recorded an estimated goodwill impairment charge of approximately $650.5 million in 2006. This sale was completed in May 2007; see Note 3 of the accompanying Notes to Consolidated Financial Statements. Prior to its sale, we referred to these operations principally as the Terasen Gas business segment.

In March 2007, we entered into an agreement to sell the Corridor Pipeline System to Inter Pipeline Fund, a Canada-based company, for approximately C$760 million, including debt. This sale was completed in June 2007. Inter Pipeline Fund also assumed all of the debt associated with the expansion taking place on Corridor at the time of the sale. Prior to its sale, the Corridor Pipeline System was included in the business segment named Kinder Morgan Canada. Also in March 2007, we completed the sale of our U.S. retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company and Alinda Investments LLC for $710 million and an adjustment for working capital. Prior to their sale, we referred to these operations as the Kinder Morgan Retail business segment. On October 5, 2007, Kinder Morgan Energy Partners announced that it had completed the sale of the North System and also its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash. Prior to its sale, the North System and the equity investment in the Heartland Pipeline were reported in the Products Pipelines–KMP business segment. In February 2008, we sold an 80% ownership interest in our NGPL business segment at a price equivalent to a total enterprise value of approximately $5.9 billion; see Note 10 of the accompanying Notes to Consolidated Financial Statements. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the financial results of the Terasen Gas, Corridor, Kinder Morgan Retail operations, the North System operations and the equity investment in the Heartland Pipeline Company have been reclassified to discontinued operations for all periods presented, and 100% of the assets and liabilities associated with the NGPL business segment were reclassified to assets and liabilities held for sale, and the non-current assets and long-term debt held for sale balances were then reduced by our 20% ownership interest in the NGPL business segment, which was recorded as an investment as of December 31, 2008 and 2007, respectively.

On April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan Energy Partners for approximately $550 million. The transaction was approved by the independent members of our board of directors and those of Kinder Morgan Management following the receipt, by each board, of separate fairness opinions from different investment banks. The Trans Mountain pipeline system transports crude oil and refined products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington. An impairment of the Trans Mountain pipeline system was recorded in the first quarter of 2007; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

On November 20, 2007, we entered into a definitive agreement to sell our interests in three natural gas-fired power plants in Colorado to Bear Stearns. The closing of the sale occurred on January 25, 2008, effective January 1, 2008, and we received net proceeds of $63.1 million.

On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system and the net assets of the Jet Fuel pipeline to Kinder Morgan Energy Partners for approximately 2 million Kinder Morgan Energy Partners’ common units worth approximately $116 million. The Express pipeline system transports crude oil from Alberta to Illinois. The Jet Fuel pipeline serves the Vancouver, British Columbia airport. Prior to the sales, we reported the results of the Trans Mountain pipeline system in the Trans Mountain–KMP segment, the equity investment in the Express pipeline system in the Express segment and the results of Jet Fuel were included in the “Other” caption in the Consolidated Financial Results table in the Management’s Discussion and Analysis of Financial Condition and Results of Operations. In order to present the prior periods consistent with the segments as now presented in 2008, these assets and their results are included in the Kinder Morgan Canada–KMP segment for all periods presented.

Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners’ financial statements is a legal determination based on the entity that incurs the liability.

Critical Accounting Policies, Estimates and Annual Goodwill Impairment Test

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and contained within this report. Certain amounts included in or affecting our consolidated financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be

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known with certainty at the time the financial statements are prepared. The reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible impairment charges, the effective income tax rate to apply to our pre-tax income, deferred income tax balances, obligations under our employee benefit plans, provisions for uncollectible accounts receivable, cost and timing of environmental remediation efforts, potential exposure to adverse outcomes from judgments or litigation settlements, exposures under contractual indemnifications and various other recorded or disclosed amounts. Certain of these accounting estimates are of more significance in our financial statement preparation process than others, which policies are discussed following. Our policies and estimation methodologies are generally the same in both the predecessor and successor company periods, except where explicitly discussed.

Environmental Matters

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

The recording of environmental accruals often coincides with the completion of a feasibility study or the commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and primarily result from quarterly reviews of potential environmental issues and resulting changes in environmental liability estimates. The environmental liability adjustments are recorded pursuant to management’s requirement to recognize environmental liabilities wherever the associated environmental issue is likely to occur and where the amount of the liability can be reasonably estimated. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. For more information on our environmental disclosures, see Note 21 of the accompanying Notes to Consolidated Financial Statements.

Legal Matters

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

As of December 31, 2008 and December 31, 2007, our most significant ongoing litigation proceedings involve Kinder Morgan Energy Partners’ West Coast Products Pipelines operations. Tariffs charged by certain of these pipeline systems are subject to certain proceedings at the Federal Energy Regulatory Commission (“FERC”) involving shippers’ complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services. Generally, the interstate rates on Kinder Morgan Energy Partners’ West Coast Products Pipelines pipeline systems are “grandfathered” under the Energy Policy Act of 1992 unless “substantially changed circumstances” are found to exist. To the extent “substantially changed circumstances” are found to exist, the West Coast Products Pipelines pipeline systems may be subject to substantial exposure under these FERC complaints and could, therefore, owe reparations and/or refunds to complainants as mandated by the FERC or the United States’ judicial system. For more information on the West Coast Products Pipelines pipeline systems’ regulatory proceedings, see Note 20 of the accompanying Notes to Consolidated Financial Statements.

Intangible Assets

Intangible assets are those assets which provide future economic benefit but have no physical substance. We account for our intangible assets according to the provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets. These accounting pronouncements introduced the concept of indefinite life intangible assets and provided that all identifiable intangible assets having indefinite useful economic lives, including goodwill, will not be subject to periodic amortization. Such assets are not to be amortized unless and until their lives are determined to be finite. Instead,

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the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. For the Predecessor Company, an impairment measurement test date of January 1 of each year was selected; for the Successor Company, we use an annual impairment measurement date of May 31.

As of December 31, 2008 and December 31, 2007, our goodwill was $4,741.1 million and $8,174.0 million, respectively. Included in these goodwill balances is $250.1 million related to the Trans Mountain pipeline, which we sold to Kinder Morgan Energy Partners on April 30, 2007. This sale transaction caused us to reconsider the fair value of the Trans Mountain pipeline system in relation to its carrying value, and to make a determination as to whether the associated goodwill was impaired. As a result of our analysis, we recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007.

Our remaining intangible assets, excluding goodwill, include customer relationships, contracts and agreements, technology-based assets and lease value. These intangible assets have definite lives, are being amortized on a straight-line basis over their estimated useful lives, and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. As of December 31, 2008 and December 31, 2007, these intangibles totaled $251.5 million and $321.1 million, respectively.

In conjunction with our annual impairment test of the carrying value of goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using a market multiple for the individual assets). The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairments by reporting unit: Products Pipelines–KMP (excluding associated terminals) $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes)—$70 million, Natural Gas Pipelines–KMP—$2.09 billion, and Terminals–KMP $677 million, for a total impairment of $4.03 billion. The goodwill impairment is a non-cash charge and does not have any impact on our cash flow. While the fair value of the CO2–KMP segment exceeded its carrying value as of the date of our goodwill impairment test, decreases in the market value of crude oil led us to reconsider this analysis as of December 31, 2008 and at that time our analysis also determined that the fair value exceeded the carrying value. If the market price of crude oil continues to decline, we may need to record non-cash goodwill impairment charges on this reporting unit in future periods.

Estimated Net Recoverable Quantities of Oil and Gas

We use the successful efforts method of accounting for Kinder Morgan Energy Partners’ oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas. Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.

Hedging Activities

We engage in a hedging program that utilizes derivative contracts to mitigate (offset in whole or in part) our exposure to fluctuations in energy commodity prices, fluctuations in currency exchange rates and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. According to the provisions of current accounting standards, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged. A perfectly effective hedge is one in which changes in the value of the derivative contract exactly offset changes in the value of the hedged item or expected cash flow of the future transactions in reporting periods covered by the derivative contract. The ineffective portion of the gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately; accordingly, our financial statements may reflect some volatility due to these hedges.

In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices. For example, when we purchase a commodity at one location and sell it at another,

7

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

Employee Benefit Plans

With respect to the amount of income or expense we recognize in association with our pension and retiree medical plans, we must make a number of assumptions with respect to both future financial conditions (for example, medical costs, returns on fund assets and market interest rates) as well as future actions by plan participants (for example, when they will retire and how long they will live after retirement). Most of these assumptions have relatively minor impacts on the overall accounting recognition given to these plans, but two assumptions in particular, the discount rate and the assumed long-term rate of return on fund assets, can have significant effects on the amount of expense recorded and liability recognized. We review historical trends, future expectations, current and projected market conditions, the general interest rate environment and benefit payment obligations to select these assumptions. The discount rate represents the market rate for a high quality corporate bond. The selection of these assumptions is further discussed in Note 16 of the accompanying Notes to Consolidated Financial Statements. While we believe our choices for these assumptions are appropriate in the circumstances, other assumptions could also be reasonably applied and, therefore, we note that, at our current level of pension and retiree medical funding, a change of 1% in the long-term return assumption would increase (decrease) our annual retiree medical expense by approximately $0.5 million ($0.5 million) and would increase (decrease) our annual pension expense by $1.8 million ($1.8 million) in comparison to that recorded in 2008. Similarly, a 1% change in the discount rate would increase (decrease) our accumulated postretirement benefit obligation by $6.4 million ($5.9 million) and would increase (decrease) our projected pension benefit obligation by $29.3 million ($26.1 million) compared to those balances as of December 31, 2008.

Income Taxes

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

Noncontrolling Interests in Consolidated Subsidiaries

As prescribed by Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, the noncontrolling ownership interest is no longer classified as an expense. Instead, Net Income is allocated between Kinder Morgan, Inc.’s stockholder and the noncontrolling interests. In addition, noncontrolling ownership interests in consolidated subsidiaries are now presented in the accompanying Consolidated Balance Sheets within equity as a separate component from our stockholder's equity. As prescribed by this Statement, we applied SFAS No. 160 for all periods presented. Also, see Note 1 of the accompanying Notes to Consolidated Financial Statements.

New Basis of Accounting

The Going Private transaction was accounted for as a purchase business combination and, as a result of the application of the Securities and Exchange Commission’s “push-down” accounting requirements, this transaction has resulted in our adoption of a new basis of accounting for our assets and liabilities. Accordingly, our assets and liabilities have been recorded at their estimated fair values as of the date of the completion of the Going Private transaction, with the excess of the purchase price over these combined fair values recorded as goodwill.

Therefore, in the accompanying financial information, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical basis of accounting for our assets and liabilities, while the amounts subsequent to the closing (the amounts labeled “Successor Company”) reflect the push-down of the investors’ new accounting basis to our financial statements. While the Going Private transaction closed on May 30, 2007, for convenience, the Predecessor Company is assumed to end on May 31, 2007 and the Successor Company is assumed to begin on June 1, 2007. The results for the two-day period, from May 30 to May 31, 2007, are not material to any of the periods presented. Additional information concerning the impact of the Going Private transaction on the accompanying financial information is contained under “Consolidated Financial Results” following.

8

Our adoption of a new basis of accounting for our assets and liabilities as a result of the Going Private transaction, the sale of our retail natural gas distribution and related operations, our Corridor operations, the North System, our 80% interest in NGPL PipeCo LLC (“PipeCo”), the goodwill impairments described above, and other acquisitions and divestitures (including the transfer of certain assets to Kinder Morgan Energy Partners), among other factors, affect comparisons of our financial position and results of operations between certain periods.

Consolidated Financial Results

The following discussion provides an analysis of material events that affected our operating results for the year ended December 31, 2008 (successor basis), seven months ended December 31, 2007 (successor basis) and five months ended May 31, 2007 (predecessor basis) and year ended December 31, 2006 (predecessor basis).

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Segment Earnings (Loss) before Depreciation, Depletion and Amortization of Excess Cost of Equity Investments1
NGPL2	$	129.8		$	422.8		$	267.4		$	603.5
Power		5.7			13.4			8.9			23.2
Products Pipelines–KMP3,8		(722.0	)		162.5			224.4			467.9
Natural Gas Pipelines–KMP4,8		(1,344.3	)		373.3			228.5			574.8
CO2–KMP8		896.1			433.0			210.0			488.2
Terminals–KMP5,8		(156.5	)		243.7			172.3			408.1
Kinder Morgan Canada–KMP6		152.0			58.8			(332.0	)		95.1
Segment Earnings (Loss) before Depreciation, Depletion and Amortization of Excess Cost of Equity Investments		(1,039.2	)		1,707.5			779.5			2,660.8
Depreciation, Depletion and Amortization Expense		(918.4	)		(472.3	)		(261.0	)		(531.4	)
Amortization of Excess Cost of Equity Investments		(5.7	)		(3.4	)		(2.4	)		(5.6	)
Other Operating Income (Loss)		39.0			(0.3	)		2.9			6.8
General and Administrative Expenses		(352.5	)		(175.6	)		(283.6	)		(305.1	)
Interest and Other, Net		(623.6	)		(586.4	)		(257.5	)		(594.0	)
Income (Loss) From Continuing Operations Before Income Taxes1		(2,900.4	)		469.5			(22.1	)		1,231.5
Income Taxes1		(301.9	)		(183.4	)		(119.9	)		(256.9	)
Income (Loss) From Continuing Operations		(3,202.3	)		286.1			(142.0	)		974.6
Income (Loss) From Discontinued Operations, Net of Tax7		(0.9	)		(1.5	)		298.6			(528.5	)
Net Income (Loss)		(3,203.2	)		284.6			156.6			446.1
Net Income Attributable to Noncontrolling Interests		(396.1	)		(37.6	)		(90.7	)		(374.2	)
Net Income Attributable to Kinder Morgan, Inc.’s Stockholder	$	3,599.3		$	247.0		$	65.9		$	71.9

__________

1 Kinder Morgan Energy Partners’ income taxes expenses for the year ended December 31, 2008, seven months ended September 30, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $2.4 million, $44.0 million, $15.6 million and $29.0 million, respectively, and are included in segment earnings.

2 Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment.

3 2008 amount includes a non-cash goodwill impairment charge of $1,266.5 million.

4 2008 amount includes a non-cash goodwill impairment charge of $2,090.2 million.

5 2008 amount includes a non-cash goodwill impairment charge of $676.6 million.

6 Includes earnings of the Trans Mountain pipeline system, Kinder Morgan Energy Partners’ interest in the Express pipeline system and the Jet Fuel pipeline system and a non-cash goodwill impairment charge of $377.1 million for the five months ended May 31, 2007.

7 2006 includes a $650.5 million goodwill impairment associated with Terasen (see Note 3 of the accompanying Notes to Consolidated Financial Statements).

8 2008 amounts include a total of $18.3 million of expense associated with hurricanes Hanna, Gustav and Ike and three terminal fires among the Terminals–KMP, Products Pipelines–KMP, Natural Gas Pipelines–KMP and CO2–KMP business segments.

Year Ended December 31, 2008

The net loss primarily resulted from a $4.03 billion non-cash goodwill impairment charge that was recorded in the second quarter of 2008 (see Note 3 of the accompanying Notes to Consolidated Financial Statements). Other items negatively

9

affecting results for the year ended December 31, 2008 include (i) reduced earning contributions from NGPL and Power as portions of these segments were sold in 2008, (ii) depreciation, depletion and amortization (“DD&A”) expense associated with expansion capital expenditures, (iii) general and administrative costs that included labor costs and associated costs for new hires during this period to support Kinder Morgan Energy Partners’ growing operations, (iv) $18.3 million of incremental expenses associated with hurricanes Hanna, Gustav and Ike and fires at three separate terminal locations and (v) lower crude oil, natural gas liquids and natural gas prices in the fourth quarter of 2008.

The net loss was partially offset by (i) contributions from Rockies Express-West, which began service in January 2008 and reached full operations in May 2008, and increasing margins in the Texas Intrastate pipelines, (ii) favorable interest expense due to the February 2008 sale of an 80% ownership interest in NGPL PipeCo LLC for approximately $5.9 billion, with the proceeds from the sale used to pay down debt, (iii) strong CO2 sales and transport volumes in the CO2–KMP segment, as well as increases of the average crude oil sale prices, (iv) the completion of expansion projects at existing facilities and recent acquisitions within the Terminals–KMP segment and (v) the completion of the pump station expansion in April 2007 and Anchor Loop expansion, which was placed in service in April 2008 (partially) and October 2008 (fully) within Kinder Morgan Canada–KMP.

Seven Months Ended December 31, 2007

Net income for the period was driven by solid contributions from CO2–KMP, NGPL, Natural Gas Pipelines–KMP and Products Pipelines–KMP, which accounted for 25.4%, 24.7%, 21.9% and 9.5%, respectively, or 81.5% collectively, of segment earnings before DD&A. CO2–KMP was driven almost equally by our sales and transport and oil and gas producing activities. The Texas Intrastate Natural Gas Pipelines Group accounted for over 50% of the Natural Gas Pipelines–KMP performance and the West Coast Products Pipelines accounted for approximately 50% of the Product Pipelines–KMP segment earnings. NGPL contributed earnings of $422.8 million with incremental earnings coming from the re-contracting of transportation and storage services at higher rates, increased contract volumes, and recent transportation and storage expansions.

Net income was adversely impacted by (i) interest expenses related to the $4.8 billion of incremental debt resulting from the Going Private transaction (see discussion below on the impact of the purchase method of accounting on segment earnings) and (ii) DD&A expense associated with expansion capital expenditures.

Five Months Ended May 31, 2007

Net income was driven by solid performance from NGPL as well as all Kinder Morgan Energy Partners segments except Kinder Morgan Canada–KMP, as discussed below. NGPL contributed $267 million while Products Pipelines–KMP, Natural Gas Pipelines–KMP and CO2–KMP each contributed over $200 million.

Offsetting these positive factors were (i) a $377.1 million goodwill impairment charge associated with the Trans Mountain Pipeline (see Note 3 of the accompanying Notes to Consolidated Financial Statements) and (ii) $141.0 million in additional general and administrative expense associated with the Going Private transaction.

Year Ended December 31, 2006

Net income for the year ended December 31, 2006 was driven by solid contributions from NGPL, Natural Gas Pipelines–KMP, CO2–KMP and Products Pipelines–KMP, which accounted for 22.7%, 21.6%, 18.4% and 17.6%, respectively, or 80.3% collectively, of segment earnings before DD&A. NGPL was driven by successful re-contracting of transportation and storage services and increased gas sales prices. The Texas Intrastate Natural Gas Pipeline Group and the western interstate natural gas pipelines group accounted for 53.1% and 35.0%, respectively, of the Natural Gas Pipelines–KMP earnings. The TransColorado pipeline system improvements completed in 2005 contributed to the western interstate natural gas pipelines group 2006 earnings. In addition, the earnings from the Trans Mountain pipeline, purchased in 2005 and part of the Kinder Morgan Canada–KMP business segment, were accretive to earnings for 2006.

Impact of the Purchase Method of Accounting on Segment Earnings (Loss)

The impacts of the purchase method of accounting on segment earnings (loss) before DD&A relate primarily to the revaluation of the accumulated other comprehensive income related to derivatives accounted for as hedges in the CO2–KMP and Natural Gas Pipelines–KMP segments. Where there is an impact to segment earnings (loss) before DD&A from the Going Private transaction, the impact is described in the individual business segment discussions, which follow. The effects on DD&A expense result from changes in the carrying values of certain tangible and intangible assets to their estimated fair values as of May 30, 2007. This revaluation results in changes to DD&A expense in periods subsequent to May 30, 2007. The purchase accounting effects on “Interest and Other, Net” result principally from the revaluation of certain debt instruments to their estimated fair values as of May 30, 2007, resulting in changes to interest expense in subsequent periods.

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Please refer to the individual business segment discussions included elsewhere in this management’s discussion and analysis for additional information regarding individual business segment results. Refer to the headings “General and Administrative Expense,” “Interest and Other, Net” and “Income Taxes—Continuing Operations” also included elsewhere herein, for additional information regarding these items.

Results of Operations

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

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

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

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to the accompanying Consolidated Statements of Operations and described in Note 1 of the accompanying Notes to Consolidated Financial Statements. Certain items included in earnings from continuing operations are either not allocated to business segments or are not considered by management in its evaluation of business segment performance. In general, the items not included in segment results are interest expense, general and administrative expenses, DD&A and income taxes. We currently evaluate business segment performance primarily based on segment earnings before DD&A in relation to the level of capital employed. Because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices. We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.

Natural Gas Pipeline Company of America

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Segment Earnings Before DD&A	$	129.8	$	422.8	$	267.4	$	603.5

On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9 billion. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest as an equity method investment. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group.

Year Ended December 31, 2008

Although we have a 20% ownership interest in NGPL, at the 100% ownership level, NGPL’s earnings before depreciation, depletion and amortization expenses for the year ended December 31, 2008 was $702.0 million. Included in the earnings for this period were (i) $650.8 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, (ii) $226.5 million of gross profit from operational gas recoveries and sales, (iii) $5.0 million of gross profit from liquids sales, (iv) $0.6 million of other revenues, (v) $15.8 million of gross profit from working and cushion sales and (vi) $7.1 million from other activities.

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These gross profits were reduced by operation and maintenance expenses of $203.8 million.

Seven Months Ended December 31, 2007

Segment revenues and earnings for the seven months ended December 31, 2007 were positively impacted primarily by (i) $334.4 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions, (ii) $116.0 million of gross profit from operational gas recoveries and sales and (iii) $61.4 million of gross profit from cushion sales. Total system throughput volumes of 1,027.2 trillion Btus in 2007 during the seven months ended December 31, 2007 did not have a significant direct impact on revenues or segment earnings due to the fact that transportation revenues are derived primarily from “firm” contracts in which shippers pay a “demand” fee to reserve a set amount of system capacity for their use.

Five Months Ended May 31, 2007

Segment revenues and earnings for the five months ended May 31, 2007 were positively impacted primarily by (i) $245.9 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions and (ii) $77.6 million of gross profit from operational gas recoveries and sales.

Year Ended December 31, 2006

Segment revenues and earnings for the year ended December 31, 2006 were positively impacted primarily by (i) $547.5 million of gross profit from transportation and storage revenues, which reflects the positive impact of re-contracting of transportation and storage services at higher rates and increased contract volumes, and recent transportation and storage system expansions and (ii) $189.4 million of gross profit from operational gas recoveries and sales.

Power

As discussed in Note 10 of the accompanying Notes to Consolidated Financial Statements, on January 25, 2008, we sold our interests in three natural gas-fired power plants in Colorado to Bear Stearns, including the Thermo Cogeneration Partnership and the Thermo Greeley facility. The closing of the sale was effective January 1, 2008, and we received net proceeds of $63.1 million.

The remaining operations for the Power segment are (i) Triton Power Michigan LLC’s lease and operation of the Jackson, Michigan 550-megawatt natural gas-fired electric power plant and (ii) a 103-megawatt natural gas-fired power plant in Snyder, Texas that generates electricity for the CO2–KMP segment’s SACROC operations, the plant’s sole customer.

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Operating Revenues	$	44.0		$	40.2		$	19.9		$	60.0
Operating Expenses and Noncontrolling Interests		(38.3	)		(34.8	)		(16.1	)		(49.6	)
Other Income (Expense)1		-			-			-			(1.2	)
Equity in Earnings of Thermo Cogeneration Partnership2		-			8.0			5.1			11.3
Gain on Asset Sales		-			-			-			2.7
Segment Earnings Before DD&A	$	5.7		$	13.4		$	8.9		$	23.2

__________

1 To record the impairment of certain surplus equipment held for sale.

2 This interest was part of the sale effective January 1, 2008 as discussed above.

Year Ended December 31, 2008

Earnings before DD&A for 2008 reflect (i) $3.4 million in earnings from the lease and operations of the Triton Power Michigan facility, (ii) a $1.5 million property tax settlement received in 2008, (iii) $0.3 million in earnings from the Snyder, Texas operations and (iv) $0.5 million from other activities.

Seven Months Ended December 31, 2007

Earnings before DD&A for the seven months ended December 31, 2007 reflect the positive impacts of (i) contributions of $2.0 million of earnings before DD&A from our Jackson, Michigan facility, (ii) $8.0 million of equity earnings from our

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investment in Thermo Cogeneration Partnership and (iii) $1.4 million of earnings from the Thermo Greeley facility associated with gas purchase and sale agreements. These favorable impacts to earnings were partially offset by an unfavorable impact to operating revenues associated with 2006 equipment sales.

Five Months Ended May 31, 2007

Earnings before DD&A for the five months ended May 31, 2007 reflect an unfavorable impact to operating revenues associated with 2006 equipment sales. These unfavorable impacts to earnings were partially offset by (i) contributions of $1.3 million of earnings from our Jackson, Michigan facility, (ii) contributions of $1.2 million of earnings from the Thermo Greeley facility associated with gas purchase and sales agreements and (iii) our $5.1 million of equity earnings from our investment in Thermo Cogeneration Partnership.

Year Ended December 31, 2006

Earnings before DD&A for the year ended December 31, 2006 reflects the positive impacts of (i) contributions of $3.1 million of earnings before DD&A from our Jackson, Michigan facility, (ii) $11.3 million of equity earnings from our investment in Thermo Cogeneration Partnership and (iii) $4.2 million of earnings from the Thermo Greeley facility associated with gas purchase and sale agreements. These favorable impacts to earnings were partially offset by an unfavorable impact to operating revenues associated with $1.9 million of equipment sales.

Products Pipelines–KMP

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions, except operating statistics)						(In millions, except operating statistics)
Operating Revenues	$	815.9		$	471.5		$	331.8		$	732.5
Operating Expenses		(291.0	)		(320.6	)		(116.4	)		(285.5	)
Other Income (Expense)		(3.0	)		0.8			(0.6	)		-
Goodwill Impairment Charge1		(1,266.5	)		-			-			-
Earnings from Equity Investments		15.7			11.5			12.4			14.2
Interest Income and Other Income, Net		2.0			4.7			4.7			11.9
Income Taxes Benefit (Expense)		4.9			(5.4	)		(7.5	)		(5.2	)
Segment Earnings (Loss) Before DD&A	$	(722.0	)	$	162.5		$	224.4		$	467.9
Operating Statistics
Gasoline (MMBbl)		398.4			252.7			182.8			449.8
Diesel Fuel (MMBbl)		157.9			97.5			66.6			158.2
Jet Fuel (MMBbl)		117.3			73.8			51.3			119.5
Total Refined Products Volumes (MMBbl)		673.6			424.0			300.7			727.5
Natural Gas Liquids (MMBbl)		27.3			16.7			13.7			34.0
Total Delivery Volumes (MMBbl)2		700.9			440.7			314.4			761.5

____________

1 2008 amount represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

2 Includes Pacific operations, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.

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Earnings Before DD&A by Major Segment Asset

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)						(In millions)
Pacific Operations	$	233.6		$	(10.3	)	$	105.1	$	245.0
Calnev Pipeline		49.2			27.5			20.1		42.2
West Coast Terminals		50.7			24.3			19.3		36.3
Plantation Pipeline		37.1			22.2			18.2		28.4
Central Florida Pipeline		41.1			21.9			15.3		31.4
Cochin Pipeline System		46.7			30.6			15.3		14.1
Southeast Terminals		51.6			24.8			16.6		37.5
Transmix Operations		29.8			18.3			12.4		28.4
Goodwill Impairment Charge		(1,266.5	)		-			-		-
All Other		4.7			3.2			2.1		4.6
Segment Earnings (Loss) Before DD&A	$	(722.0	)	$	162.5		$	224.4	$	467.9

Revenues by Major Segment Asset

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Pacific Operations	$	374.6	$	224.4	$	156.0	$	362.0
Calnev Pipeline		71.4		41.9		27.7		66.2
West Coast Terminals		79.5		42.9		29.1		64.5
Plantation Pipeline		44.0		24.6		17.6		41.2
Central Florida Pipeline		52.4		27.1		19.3		43.1
Cochin Pipeline System		63.3		42.6		32.3		35.7
Southeast Terminals		81.9		38.4		29.9		81.1
Transmix Operations		42.4		25.8		17.5		32.8
All Other (Including Eliminations)		6.4		3.8		2.4		5.9
Total Segment Operating Revenues	$	815.9	$	471.5	$	331.8	$	732.5

Year Ended December 31, 2008

Earnings before DD&A were positively affected by strong earnings for the Southeast terminals, Cochin Pipeline, Central Florida Pipeline and West Coast Terminals operations that were principally from (i) favorable margins on liquids inventory sales, (ii) incremental terminal throughput and storage activity, (iii) solid demand for ethanol and (iv) incremental returns from the completion of a number of capital expansion projects that modified and upgraded terminal infrastructure, enabling Kinder Morgan Energy Partners to provide additional ethanol-related services to its customers. The Central Florida Pipeline also benefited from strong product delivery revenues, driven by an increase in the average tariff per barrel moved as a result of a mid-year 2007 tariff rate increase on product deliveries. The Cochin Pipeline also benefited from a year-end 2008 reduction in income tax expense, related to lower Canadian operating results in 2008 and from Canadian income tax liability adjustments. The decrease in income tax expense more than offset the drop in operating revenues.

Earnings before DD&A were adversely affected by (i) a $1,266.5 million goodwill impairment charge, (ii) $20.0 million for charges, net of tax related to settlement of certain litigation matters or environmental liability adjustments, mostly related to Pacific operations’ East Line pipeline and (iii) Pacific operations expenses for major maintenance and pipeline integrity expenses.

Seven Months Ended December 31, 2007

The results for the seven months were negatively impacted by $154.9 million of legal liability adjustments primarily associated with the Pacific operations. Offsetting the charges, earnings before DD&A for this segment were positively affected by (i) approximately $15.4 million associated with Kinder Morgan Energy Partners’ January 1, 2007 acquisition of

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the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) strong pipeline revenues from the Plantation Pipeline for the period, largely due to favorable oil loss allowance tariff rates, relative to pipeline operating expenses that included only minor pipeline integrity expenses, (iii) favorable margins and strong mainline delivery volumes from the 2006 East Line pipeline expansion and demand from West Coast military bases within the Pacific operations, (iv) military and commercial tariff rate increases in 2007 on the Calnev Pipeline, (v) strong demand for terminal services at the Carson/Los Angeles Harbor terminal system, recently expanded in 2006, and the Linnton and Willbridge terminals located in Portland, Oregon, included in the West Coast Terminals operations, (vi) $4.8 million of earnings before DD&A and $5.7 million of revenue generated by the Kinder Morgan Energy Partners’ approximate $11 million Greensboro facility, placed in service in 2006, which is used for petroleum pipeline transmix operations and (vii) the West Coast Terminals operation’s $3.6 million gain on the sale of its interest in the Black Oil pipeline system in Los Angeles, California in June 2007.

Five Months Ended May 31, 2007

The results for the five months were negatively impacted by a $2.2 million expense associated with Pacific operations’ East Line pipeline legal liability adjustments. Earnings before DD&A were positively affected by (i) approximately $7.7 million associated with Kinder Morgan Energy Partners’ January 1, 2007 acquisition of the remaining ownership interest in Cochin (approximately 50.2%) that it did not already own, at which time Kinder Morgan Energy Partners became the pipeline operator, (ii) an increase in average tariff rates and mainline delivery from the 2006 expansion of the East Line pipeline within the Pacific operations and demand from West Coast military bases, which contributed to the Pacific operations’ revenues and earnings, (iii) strong demand for throughput volumes at the combined Carson/Los Angeles Harbor terminal system and the Linnton and Willbridge terminals located in Portland, Oregon, for the West Coast Terminals operations and (iv) $2.8 million of earnings before DD&A and $3.3 million of revenue generated by the Kinder Morgan Energy Partners’ Greensboro facility discussed above.

Year Ended December 31, 2006

Earnings before DD&A for 2006 were positively impacted by (i) contributions from the Pacific operations and the Calnev operations with solid refined products deliveries and terminal and other fee revenues that more than offset operating costs for the period which were affected by high fuel and power expenses, (ii) positive performance from the Southeast Terminals products operations with strong demand for liquids throughput volumes at favorable rates and optimal margins on ethanol blending and sales activities and (iii) solid product delivery revenues in 2006 from other segment assets driven by Central Florida Pipeline’s increased average tariff and terminal rates during the period.

Partially offsetting these positive factors in 2006 were (i) $13.5 million of legal liability adjustments associated with the Pacific operations, (ii) incremental pipeline maintenance expenses recognized in the last half of the year, (iii) $6.2 million of environmental expenses recognized by the West Coast Terminals operations in 2006 and (iv) $3.0 million of environmental liability adjustments (net of tax benefits) on the Plantation Pipe Line Company. Beginning in the third quarter of 2006, the refined petroleum products pipelines and associated terminal operations included within the Products Pipelines–KMP segment (including Plantation Pipe Line Company, the 51%-owned equity investee) began recognizing certain costs incurred as part of its pipeline integrity management program as maintenance expense in the period incurred, and in addition, recorded an expense for costs previously capitalized during the first six months of 2006. Combined, this change reduced the segment’s earnings before DD&A by $24.2 million in 2006—increasing maintenance expenses by $20.1 million, decreasing earnings from equity investments by $6.6 million and decreasing income tax expenses by $2.5 million.

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

Contributing to the total delivery volumes of refined petroleum products were (i) the East Line expansion, which was in service for the last seven months of 2006 and substantially increased pipeline capacity from El Paso, Texas to Tucson and Phoenix, Arizona and (ii) strong demand from the Southern California and Las Vegas, Nevada markets on the Calnev Pipeline. Partially offsetting these factors was shortened demand for throughput volumes on Plantation Pipeline, which was impacted by a competing pipeline that began service in mid-2006.

Other Products Pipelines – KMP Segment Events

Effective October 5, 2007, Kinder Morgan Energy Partners sold its North System common carrier natural gas liquids pipeline and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash, and used the proceeds received to pay down short-term debt borrowings. The North System business results of operations are not included in the tables and discussion above and have been classified to Discontinued Operations on the accompanying Statements of Operations for the seven months ended December 31, 2007, five months ended May 31, 2007

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and year ended December 31, 2006.

Natural Gas Pipelines–KMP

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions, except operating statistics)						(In millions, except operating statistics)
Operating Revenues	$	8,422.0		$	3,825.9		$	2,640.6		$	6,577.7
Operating Expenses		(7,803.3	)		(3,461.4	)		(2,418.5	)		(6,057.8	)
Other Income (Expense)		0.2			1.9			(0.1	)		15.1
Goodwill Impairment Charge1		(2,090.2	)		-			-
Earnings from Equity Investments		113.4			10.3			8.9			40.5
Interest Income and Other Income, Net		16.3			-			0.2			0.7
Income Taxes		(2.7	)		(3.4	)		(2.6	)		(1.4	)
Segment Earnings (Loss) Before DD&A	$	(1,344.3	)	$	373.3		$	228.5		$	574.8
Operating Statistics
Natural Gas Transport Volumes (Trillion Btus)2		2,156.3			1,067.0			645.6			1,440.9
Natural Gas Sales Volumes (Trillion Btus)3		866.9			519.7			345.8			909.3

__________

1 2008 amount represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

2 Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC and Texas Intrastate Natural Gas Pipeline Group pipeline volumes.

3 Represents Texas Intrastate Natural Gas Pipeline Group volumes.

Earnings Before DD&A by Major Segment Asset

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Texas Intrastate Natural Gas Pipeline Group	$	385.6		$	221.1		$	133.0		$	305.5
Kinder Morgan Interstate Gas Transmission		114.4			65.7			43.1			107.4
Trailblazer Pipeline		44.4			31.9			18.1			50.8
TransColorado Pipeline		55.0			25.7			17.9			43.1
Rockies Express Pipeline		84.4			(8.3	)		(4.3	)		-
Kinder Morgan Louisiana Pipeline		11.3			-			-			-
Casper and Douglas Gas Processing		20.0			18.0			7.3			29.3
Goodwill Impairment Charge		(2,090.2	)		-			-			-
All Others		30.8			19.2			13.4			38.7
Segment Earnings (Loss) Before DD&A	$	(1,344.3	)	$	373.3		$	228.5		$	574.8

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Revenues by Major Segment Asset

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Texas Intrastate Natural Gas Pipeline Group	$	7,979.4		$	3,562.0		$	2,492.4		$	6,196.6
Kinder Morgan Interstate Gas Transmission		199.5			130.7			70.7			183.6
Trailblazer Pipeline		53.9			36.4			22.6			50.1
TransColorado Pipeline		63.5			30.3			20.7			47.9
Rockies Express Pipeline		-			-			-			0.7
Casper and Douglas Gas Processing		126.3			67.1			34.7			96.2
All Others		3.0			0.2			-			4.1
Eliminations		(3.6	)		(0.8	)		(0.5	)		(1.5	)
Segment Revenues	$	8,422.0		$	3,825.9		$	2,640.6		$	6,577.7

Year Ended December 31, 2008

The Natural Gas Pipelines–KMP segment’s earnings before DD&A in the year ended December 31, 2008 were driven by (i) a strong performance by the Texas Intrastate Natural Gas Pipeline Group due to (a) higher natural gas sales margins, (b) increased transportation service revenues due to long-term contract with a major customer that became effective April 1, 2007 and (c) greater natural gas processing revenues, (ii) contributions from Kinder Morgan Energy Partners’ 51% ownership interest in the Rockies Express Pipeline LLC, whose Rockies Express-West pipeline segment became fully operational in May 2008, (iii) a strong performance from the TransColorado Pipeline primarily due to contract improvements and expansions completed since the end of the third quarter of 2007, (iv) strong performance from the Kinder Morgan Interstate Gas Transmission system (“KMIGT”) primarily due to decreased electricity used and lower negotiated rates, lower natural gas purchase costs and lower tax expenses payable to the state of Texas in 2008. Also, in October 2008, KMIGT completed construction on an approximately $22 million expansion project that provides for the delivery of natural gas to five separate industrial plants (four of which produce ethanol) located near Grand Island, Nebraska. The project is fully subscribed with long-term customer contracts; and (v) earnings from the Kinder Morgan Louisiana Pipeline that benefited from FERC regulations governing allowances for capital funds that are used for pipeline construction costs (an equity cost of capital allowance).

Offsetting the above positive impacts to the segment’s earnings before DD&A were the following: (i) a $2,090.2 million goodwill impairment charge, (ii) the Casper and Douglas gas processing operations were adversely affected by higher natural gas purchase costs, due to increases in both prices and volumes, which more than offset revenue increases resulting from both higher average prices on natural gas liquids sales and higher revenues from sales of excess natural gas and (iii) the Trailblazer Pipeline’s earnings were affected by lower revenues from both natural gas transportation services and sales of excess natural gas.

Seven Months Ended December 31, 2007

Earnings before DD&A in the seven months ended December 31, 2007 were also positively affected by (i) strong performances by the Texas Intrastate Pipeline group due to (a) favorable natural gas sales margins on renewal contracts, (b) increased transportation service revenue due to a new long-term contract with a major customer that became effective April 1, 2007, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from transportation and storage under a new long term contract with a major customer that became effective April 1,2007, (ii) strong performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.

Adversely affecting earnings before DD&A in the seven months ended December 31, 2007 was Kinder Morgan Energy Partners’ share of net losses from its equity investment in Rockies Express Pipeline LLC due to depreciation and interest expenses allocable to a segment of this project that was placed in service in February 2007, and until the completion of the Rockies Express-West project which became fully operational in May 2008, generated only limited natural gas reservation revenues and volumes. See Note 19 of the accompanying Notes to Consolidated Financial Statements for additional information on the Rockies Express Pipeline project.

17

Five Months Ended May 31, 2007

Earnings before DD&A in the five months ended May 31, 2007 were positively affected by (i) strong performances by the Texas Intrastate Natural Gas Pipeline Group due to (a) favorable natural gas sales margins on renewal and incremental contracts, (b) strong demand for and favorable rates on transportation services, (c) greater value from natural gas storage activities and natural gas processing margins, (d) sales of cushion gas due to the termination of a storage facility lease and (e) storage revenues from a new long-term contract with a major customer that became effective April 1, 2007, (ii) strong performance from KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings from transportation and natural gas park and loan services and (iii) earnings from Casper and Douglas gas processing operations that had solid natural gas liquids sales revenues driven by favorable prices and volumes.

Rockies Express Pipeline LLC operations adversely affected earnings before DD&A by $4.3 million for the five months ended May 31, 2007 as depreciation and interest expenses were in excess of gross profits realized on limited natural gas reservation revenues and volumes, as discussed above in the Seven Months Ended December 31, 2007 discussion.

Year Ended December 31, 2006

Combined, gains on sales of gas processing facilities and the revaluation of purchase/sale contracts increased earnings before DD&A by $21.4 million in the year ended December 31, 2006. Earnings before DD&A in 2006 were also positively impacted by (i) a strong revenue stream with favorable imbalance resolution from the Texas Intrastate Natural Gas Pipeline Group, (ii) revenues earned in 2006 from both operational sales of natural gas and natural gas park and loan services by KMIGT, (iii) natural gas transmission revenues earned by TransColorado Pipeline, chiefly related to strong natural gas delivery volumes resulting from both system improvements and the successful negotiation of incremental firm transportation contracts and (iv) increased prices during the period on incremental sales of excess fuel gas and strong natural gas gathering revenues from the 49% equity investment in the Red Cedar Gathering Company within the “All Others” assets group in the tables above.

KMIGT’s operational gas sales are primarily made possible by its collection of fuel in-kind pursuant to its transportation tariffs and recovery of storage cushion gas volumes. The TransColorado Pipeline system improvements were associated with a 2005 expansion on the northern portion of the pipeline.

CO2–KMP

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions, except operating statistics)						(In millions, except operating statistics)
Operating Revenues	$	1,269.2		$	605.9		$	324.2		$	736.5
Operating Expenses		(391.8	)		(182.7	)		(121.5	)		(268.1	)
Earnings from Equity Investments		20.7			10.5			8.7			19.2
Other Income (Expense), Net		1.9			0.1			(0.1	)		0.8
Income Taxes		(3.9	)		(0.8	)		(1.3	)		(0.2	)
Segment Earnings Before DD&A	$	896.1		$	433.0		$	210.0		$	488.2
Operating Statistics
Carbon Dioxide Delivery Volumes (Bcf)1		732.1			365.0			272.3			669.2
SACROC Oil Production (Gross)(MBbl/d)2		28.0			26.5			29.1			30.8
SACROC Oil Production (Net)(MBbl/d)3		23.3			22.1			24.2			25.7
Yates Oil Production (Gross)(MBbl/d)2		27.6			27.4			26.4			26.1
Yates Oil Production (Net)(MBbl/d)3		12.3			12.2			11.7			11.6
Natural Gas Liquids Sales Volumes (Net)(MBbl/d)3		8.4			9.5			9.7			8.9
Realized Weighted-average Oil Price per Bbl4,5	$	49.42		$	36.80		$	35.03		$	31.42
Realized Weighted-average Natural Gas Liquids Price per Bbl5,6	$	63.00		$	58.55		$	45.04		$	43.90

__________

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

2 Represents 100% of the production from the field. Kinder Morgan Energy Partners owns an approximate 97% working interest in the SACROC unit and an approximate 50% working interest in the Yates unit.

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

4 Includes all Kinder Morgan Energy Partners crude oil production properties.

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

6 Includes production attributable to leasehold ownership and production attributable to Kinder Morgan Energy Partners’ ownership in processing plants and third-party processing agreements.

Because the CO2–KMP segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, it mitigates this risk through a long-term hedging strategy that is intended to generate more stable realized prices by using derivative contracts as hedges to the exposure of fluctuating expected future cash flows produced by changes in commodity sales prices. All of the hedge gains and losses for crude oil and natural gas liquids are included in the realized weighted average price for oil. Had energy derivative contracts not been used to transfer commodity price risk, crude oil sales prices would have averaged $97.70 per barrel in 2008, $78.65 per barrel in the seven months ended December 31, 2007, $57.43 per barrel in the five months ended May 31, 2007 and $63.27 per barrel in 2006. For more information on hedging activities, see Note 15 of the accompanying Notes to Consolidated Financial Statements.

Additionally, the decline in crude oil production at the SACROC field unit in the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 is attributable to lower observed recoveries from recent project areas and an intentional slow down in development pace given this reduction in recoveries. For more information on Kinder Morgan Energy Partners’ ownership interests in the net quantities of proved oil and gas reserves and its measures of discounted future net cash flows from oil and gas reserves, please see the caption titled “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” in the Financial Statements and Supplementary Data included in Item 8 of this report.

Earnings Before DD&A by Major Segment Activities

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Sales and Transportation	$	301.0	$	110.4	$	67.2	$	186.8
Oil and Gas Production		595.1		322.6		142.8		301.4
Segment Earnings Before DD&A	$	896.1	$	433.0	$	210.0	$	488.2

Revenues by Major Segment Activities

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Sales and Transportation	$	334.7		$	116.1		$	71.3		$	196.3
Oil and Gas Production		1,019.2			518.7			271.7			601.0
Eliminations		(84.7	)		(28.9	)		(18.8	)		(60.8	)
Total Segment Operating Revenues	$	1,269.2		$	605.9		$	324.2		$	736.5

Year Ended December 31, 2008

The CO2–KMP segment’s earnings before DD&A in the year ended December 31, 2008 were positively affected by the realization of higher market and hedge prices for the sale of its crude oil, natural gas products and CO2 and an expansion project completed in its sales and transportation business, which increased CO2 delivery volumes. Another positive impact on the period’s earnings before DD&A of $136.3 million resulted from valuation adjustments related to derivative contracts on crude oil hedges in place at the time of the Going Private transaction and recorded in the application of the purchase method of accounting.

Earnings for the segment’s sales and transportation activities were positively impacted by factors affecting carbon dioxide sales revenues (both price and volume related) and carbon dioxide and crude oil pipeline transportation revenues. Transportation revenues were impacted by increased carbon dioxide delivery volume due to rising customer demand for carbon dioxide for use in oil recovery projects throughout the Permian Basin. Another positive impact during 2008 in carbon dioxide sales and delivery volumes was the January 17, 2008 start-up of the Doe Canyon Deep unit carbon dioxide source field located in Dolores County, Colorado. Kinder Morgan Energy Partners holds an approximately 87% working interest in the Doe Canyon Deep unit.

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With respect to crude oil, overall sales volumes were essentially flat, but the segment benefited from an increase in its realized weighted-average price per barrel. With respect to natural gas liquids, a decrease in sales volumes was more than offset by increases in its realized weighted-average price per barrel. Sales volumes were adversely affected by Hurricane Ike, which resulted in pro-rationing (production allocation).

Seven Months Ended December 31, 2007

For the seven months ended December 31, 2007, SACROC’s gross production averaged 26.5 thousand barrels per day and Yates’ gross production averaged 27.4 thousand barrels per day. SACROC contributed approximately 56% of earnings before DD&A for the total oil and gas producing activities. The earnings before DD&A in the seven months ended December 31, 2007 were positively affected by (i) strong average crude oil and natural gas plant product prices, (ii) strong oil production at the Yates field unit and (iii) a favorable realized weighted-average price per barrel in the SACROC field unit gas processing operations. The period’s results were also positively affected by valuation adjustments of $106.0 million for derivative contracts on crude oil hedges as described above in the Year Ended December 31, 2008 discussion.

Partially offsetting these factors was a reduced average carbon dioxide realized sales price resulting from the December 2006 expiration of a large volume high-priced sales contract.

With respect to crude oil, overall sales volumes were stable, but the segment benefited from a strong realized weighted-average price per barrel. With respect to natural gas liquids, low sales volumes were more than offset by a favorable realized weighted-average price per barrel.

Five Months Ended May 31, 2007

The segment’s sales and transportation activities were adversely affected by a decrease in average carbon dioxide prices. A significant portion of the decrease in average carbon dioxide prices is timing related, as some of the segment’s carbon dioxide contracts are tied to crude oil prices in prior periods, and the 2007 contracts had been tied to lower crude oil prices, relative to 2006. These decreases in carbon dioxide prices were only partially offset by slightly higher carbon dioxide sales volumes related to increased carbon dioxide production from the McElmo Dome source field.

Highlights surrounding oil and gas producing activities for the five months ended May 31, 2007 include (i) increases in oil production at the Yates field unit, (ii) favorable weighted-average price per barrel and (iii) solid earnings from natural gas liquids sales volumes and prices, largely due to increased recoveries at the SACROC gas processing operations.

Year Ended December 31, 2006

Earnings before DD&A in 2006 were driven by strong earnings from carbon dioxide sales and transportation activities, largely due to solid revenues—from both carbon dioxide sales and deliveries, and from crude oil pipeline transportation, despite only modest earnings from oil and gas producing activities and equity earnings from the segment’s 50% ownership interest in Cortez Pipeline Company. Earnings from oil and gas producing activities were positively impacted during the period primarily by rising realized sales prices and partly from increased crude oil production at the Yates field unit, however partially offsetting these factors were increased operating and maintenance expenses (including well workover expenses), property and severance taxes, and fuel and power expenses.

20

Terminals–KMP

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions, except operating statistics)						(In millions, except operating statistics)
Operating Revenues	$	1,173.6		$	599.2		$	364.5		$	864.8
Operating Expenses		(631.8	)		(344.2	)		(192.2	)		(461.9	)
Other Income (Expense)		(6.4	)		3.3			3.0			15.2
Goodwill Impairment Charge1		(676.6	)		-			-			-
Earnings from Equity Investments		2.7			0.6			-			0.2
Interest Income and Other Income, Net		1.7			0.7			0.3			2.1
Income Taxes		(19.7	)		(15.9	)		(3.3	)		(12.3	)
Segment Earnings (Loss) Before DD&A	$	(156.5	)	$	243.7		$	172.3		$	408.1
Operating Statistics
Bulk Transload Tonnage (MMtons)2		99.1			62.5			33.7			95.1
Liquids Leaseable Capacity (MMBbl)		54.2			47.5			43.6			43.5
Liquids Utilization %3		97.5	%		95.9	%		97.5	%		96.3	%

__________

1 2008 amounts include a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

2 Volumes for acquired terminals are included for all periods.

3 Represents percentage of utilized available terminal storage capacity.

Kinder Morgan Energy Partners earnings have benefited from the incremental contributions attributable to the bulk and liquids terminal businesses it has built or acquired between 2005 and 2008. These transactions have included (among others):

· the Texas Petcoke terminals acquisition on April 29, 2005;

· three separate terminals located in New York, Kentucky and Arkansas, which were acquired in July 2005;

· the purchase of all of the ownership interests in General Stevedores, L.P. on July 31, 2005;

· the acquisition of the Kinder Morgan Blackhawk terminal located in Black Hawk County, Iowa, in August 2005;

· the September 2005 purchase of a terminal-related repair shop located in Jefferson County, Texas;

· three terminal operations, which were 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;

· all of the membership interests of Transload Services, LLC, which were acquired on November 20, 2006;

· all of the membership interests of Devco USA L.L.C., which were purchased on December 1, 2006;

· the Vancouver Wharves bulk marine terminals, acquired on May 30, 2007;

· the terminal assets from Marine Terminals, Inc., purchased on September 1, 2007;

· Phase III expansions completed and put into service at the Pasadena and Galena Park, Texas liquids terminal facilities in the first quarter of 2008;

· nine new storage tanks at the Perth Amboy, New Jersey liquids terminal, which were completed and put into service in the first quarter of 2008;

· a barge unloading terminal located on 30 acres in Columbus, Mississippi, completed and put into service in the first quarter of 2008;

· our Pier X expansion at our bulk handling facility located in Newport News, Virginia, completed and put into service in the first quarter of 2008;

· the approximately 2.15 million barrels of new crude oil capacity at the Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada, which was completed and put into service in the second quarter of 2008;

· the approximately 320,000 barrels of additional gasoline capacity at the Shipyard River Terminal located in Charleston, South Carolina, which was completed and put into service in the third quarter of 2008;

· the Kinder Morgan Wilmington terminal, purchased on August 15, 2008; and

· the acquisition of certain terminal assets from LPC Packaging on October 2, 2008.

Year Ended December 31, 2008

Segment earnings before DD&Awere positively affected by improved performance from existing assets such as $57.2 million of total 2008 earnings before DD&A from the Texas Petcoke terminal operations and assets acquired or expanded in

21

the last eighteen months including (i) $8.3 million from the Vancouver Wharves bulk marine terminal, (ii) $22.1 million from Marine Terminals, Inc. and other acquired operations, (iii) $139.0 million from Kinder Morgan Energy Partners’ Gulf Coast terminals, primarily from its two expanded large liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, (iv) $60.9 million from the Mid-Atlantic terminals, including strong coal transfer volumes primarily from its Pier IX bulk terminal (including earnings from the first quarter 2008 completion of construction of a new ship dock and installation of added terminal equipment) located in Newport News, Virginia and its Fairless Hills, Pennsylvania bulk terminal that began operations in the second quarter of 2008 with a new import fertilizer facility, (v) $30.5 million from the Western terminals, primarily from its recently completed North 40 terminal and (vi) $74.2 million from the Northeast terminals, primarily from its Perth Amboy, New Jersey liquids terminal, located in the New York Harbor area, driven by liquids throughput volumes as a result of an expansion completed at the end of the first quarter of 2008.

Segment earnings before DD&A for this period were adversely impacted by (i) a $676.6 million goodwill impairment charge and (ii) $12.9 million in hurricane and fire damage clean-up, repair and write-offs, net of income tax benefit.

Seven Months Ended December 31, 2007

Combined, the operations acquired in 2006 and 2007 referred to above contributed earnings before DD&A of $28.4 million, revenues of $73.3 million, operating expenses of $45.4 million and equity earnings of $0.5 million in the seven months ended December 31, 2007. This segment’s earnings benefited from the two large Gulf Coast liquids terminal facilities located along the Houston Ship Channel in Pasadena and Galena Park, Texas, which contributed $18.1 million of combined earnings before DD&A. The two terminals continued to benefit from both recent expansions that have added new liquids tank and truck loading rack capacity since 2006 and business from ethanol and biodiesel storage and transfer activity. Strong earnings during the period also resulted from (i) $12.1 million of earnings before DD&A contributed from the combined operations of the Argo and Chicago, Illinois liquids terminals, due to strong ethanol throughput and increased capacity in the liquids storage and handling business, (ii) $30.9 million of earnings before DD&A contributed from the Texas Petcoke terminals, due largely to strong demand for petroleum coke at the Port of Houston facility and (iii) $5.5 million of earnings before DD&A contributed from the Pier IX bulk terminal, located in Newport News, Virginia, largely due to a favorable demand for coal transfers and increasing rail incentives.

Five Months Ended May 31, 2007

Acquisitions in 2006 and 2007 as described above contributed $2.8 million in earnings before DD&A during the five months ended May 31, 2007 were composed of (i) $2.0 million from Transload Services, LLC and (ii) $0.8 million from Devco USA L.L.C. Segment earnings before DD&A also included strong earnings contributions consisting of (i) $5.9 million from Kinder Morgan Energy Partners’ Shipyard River terminal located in Charleston, South Carolina; (ii) $17.3 million from the Lower Mississippi (Louisiana) terminals (which include its 66 2/3% ownership interest in the International Marine Terminals partnership and the Port of New Orleans liquids facility located in Harvey, Louisiana) and (iii) $7.8 million from the combined operations of its Argo and Chicago, Illinois liquids terminals. The increases from the Shipyard River terminal related to completed expansion projects since the middle of 2006 that increased handling capacity for imported coal volumes and the earnings increases from the Chicago liquids facilities were driven by higher revenues, due to increased ethanol throughput and incremental liquids storage and handling business.

Year Ended December 31, 2006

Combined, the terminal acquisitions in 2005 and 2006, mentioned above, accounted for incremental amounts of earnings before DD&A of $33.5 million, revenues of $68.8 million and operating expenses of $35.3 million, respectively, in 2006. A majority of these increases in earnings, revenues, and expenses were attributable to the inclusion of the Texas petcoke terminals, which were acquired from Trans-Global Solutions, Inc. on April 29, 2005.

The segment’s earnings before DD&A also benefited from (i) a solid revenue stream from the Pasadena and Galena Park Gulf Coast liquids terminals, driven by new and incremental customer agreements, additional liquids tank capacity from capital expansions completed at the Pasadena terminal since the end of 2005, increased truck loading rack service fees during the period, strong demand from ethanol throughput and revenues from customer deficiency charges, (ii) strong revenues from liquids warehousing and coal and cement handling at the Shipyard River terminal, located in Charleston, South Carolina, (iii) strong demand for petroleum coke handling from the Texas Petcoke terminals and (iv) contributions from the Lower Mississippi River (Louisiana) terminals, primarily due to incremental earnings from the Amory and DeLisle Mississippi bulk terminals. The Amory terminal began operations in July 2005. The earnings from the DeLisle terminal resulted from solid bulk transfer revenues in 2006.

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Kinder Morgan Canada–KMP

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions, except operating statistics)						(In millions, except operating statistics)
Operating Revenues	$	198.9		$	100.9		$	62.0		$	140.8
Operating Expenses		(68.0	)		(44.3	)		(23.1	)		(54.9	)
Earnings from Equity Investment		8.3			14.4			5.4			17.2
Other Income (Expense)1		-			-			(377.1	)		0.9
Interest Income and Other Income (Expense), Net2		(6.2	)		6.3			1.7			1.0
Income Tax Benefit (Expense)3		19.0			(18.5	)		(0.9	)		(9.9	)
Segment Earnings (Loss) Before DD&A	$	152.0		$	58.8		$	(332.0	)	$	95.1
Operating Statistics
Transport Volumes (MMBbl)		86.7			58.0			36.4			83.7

__________

1 Amount for the five months ended May 31, 2007 represents a non-cash goodwill impairment charge; see Note 3 of the accompanying Notes to Consolidated Financial Statements.

2 2008 amount includes a $12.3 million expense due to certain non-cash Trans Mountain regulatory accounting adjustments.

3 2008 amount includes a $19.3 million decrease in expense associated with favorable changes in Canadian income tax rates and a $6.6 million increase in expense due to certain non-cash Trans Mountain regulatory accounting adjustments.

The information in the table above reflects the results of operations for the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 as though the transfer of the Trans Mountain one-third interest in Express and Jet Fuel to Kinder Morgan Energy Partners had occurred at the beginning of the period (January 1, 2006).

Year Ended December 31, 2008

In addition to the $12.7 million net favorable impact in Canadian income taxes described in footnote 3 to the table above, earnings before DD&A for the year ended December 31, 2008 include strong operating revenues resulting from the April 2007 completion of an expansion project that included the commissioning of ten new pump stations that boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels per day, and to the April 28, 2008 partial completion of the first portion of the Anchor Loop expansion that boosted pipeline capacity from 260,000 to 285,000 barrels per day and resulted in higher period-to-period average toll rates. Kinder Morgan Energy Partners completed construction on a final 15,000 barrels per day expansion on October 30, 2008 and total pipeline capacity is now approximately 300,000 barrels per day.

Seven Months Ended December 31, 2007

During seven months ended December 31, 2007, segment earnings before DD&A were positively impacted by the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.

Five Months Ended May 31, 2007

During the five months ended May 31, 2007, earnings before DD&A were adversely affected by a $377.1 million goodwill impairment charge recorded against the Trans Mountain asset. Slightly offsetting this negative impact to earnings was the completion of a pump station expansion on April 30, 2007 and its associated positive impact to revenue for the period.

Year Ended December 31, 2006

Trans Mountain, the one-third interest in Express and the full interest in the net assets of Jet Fuel were acquired on November 30, 2005 as part of the Terasen acquisition. 2006 was the first full year that these assets were included in the Consolidated Statements of Operations.

In 2006, Kinder Morgan Canada–KMP started the expansion of the Trans Mountain pipeline system, which is discussed above.

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General and Administrative Expense

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Kinder Morgan, Inc. General and Administrative Expense	$	(54.6	)	$	(33.2	)	$	(138.6	)	$	(36.9	)
Kinder Morgan Energy Partners General and Administrative Expense		(297.9	)		(142.4	)		(136.2	)		(238.4	)
Terasen General and Administrative Expenses		-			-			(8.8	)		(29.8	)
Consolidated General and Administrative Expense	$	(352.5	)	$	(175.6	)	$	(283.6	)	$	(305.1	)

Year Ended December 31, 2008

“General and Administrative Expense” for the year ended December 31, 2008 of $352.5 million primarily consists of (i) $209.7 million of Kinder Morgan Energy Partners compensation expense, (ii) $57.8 million of Kinder Morgan Energy Partners outside services and (iii) $45.1 million incurred by Kinder Morgan,, Inc. general and administrative expenses related to Natural Gas Pipeline Company of America LLC (“NGPL G&A”).  $6.2 million of the $45.1 million NGPL G&A was incurred during the period prior to the sale of an 80% interest in NGPL PipeCo LLC, January 1, 2008 through February 14, 2008, and the remaining $38.9 million was incurred subsequent to February 15, 2008 and billed to Natural Gas Pipeline Company of America LLC; see Note 7 in the accompanying Notes to Consolidated Statements for more information.

Seven Months Ended December 31, 2007

“General and Administrative Expense” for the seven months ended December 31, 2007 includes $33.2 million of Kinder Morgan, Inc. general and administrative expense, primarily associated with $19.4 million of compensation expense and $142.4 million of Kinder Morgan Energy Partners general and administrative expense, primarily associated with $108.6 million of compensation expense and $28.8 million of outside services.

Five Months Ended May 31, 2007

“General and Administrative Expense” for the five months ended May 31, 2007 includes a total of $141.0 million related to the going private transaction, consisting of $114.8 million expensed by Kinder Morgan, Inc. and $26.2 million allocated to Kinder Morgan Energy Partners. In addition, during the five months ended May 31, 2007 we incurred $4.3 million in selling expenses associated with the sale of our (i) U.S. based retail natural gas distribution and related operations, (ii) Terasen Gas business and (iii) Terasen Pipelines (Corridor) Inc.

Year Ended December 31, 2006

“General and Administrative Expense” for the year ended December 31, 2006 includes $36.9 million of Kinder Morgan, Inc. general and administrative expense, primarily associated with $19.5 million of compensation expense and $238.4 million of Kinder Morgan Energy Partners general and administrative expense, primarily associated with $144.3 million of compensation expense and $46.8 million of outside services.

Kinder Morgan Energy Partners’ and Kinder Morgan, Inc.’s general and administrative expenses tend to increase over time in large part because the expansion of their businesses through acquisitions and internal growth requires the hiring of additional employees, resulting in increased payroll and other employee-related expense.

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Interest and Other, Net

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Interest Expense, Net	$	(633.4	)	$	(581.5	)	$	(241.1	)	$	(552.8	)
Interest Income (Expense) – Deferrable Interest Debentures2		5.1			(12.8	)		(9.1	)		(21.9	)
Consolidated Interest Expense		(628.3	)		(594.3	)		(250.2	)		(574.7	)
Loss on Mark-to-market Interest Rate Swaps		-			-			-			(22.3	)
Other1		4.7			7.9			(7.3	)		3.0
	$	(623.6	)	$	(586.4	)	$	(257.5	)	$	(594.0	)

__________

1 “Other” represents offset to noncontrolling interest and interest income shown above and included in segment earnings.

2 2008 amount includes $11.3 million gain on retirement, offset by $5.751 million interest expense and $0.5 million of accounting expense.

“Interest Expense, Net” for the year ended December 31, 2008 includes (i) $388.2 million of Kinder Morgan Energy Partners interest expense and (ii) $240.1 million of Kinder Morgan, Inc. interest expense. Kinder Morgan Energy Partners interest expense tends to increase over time as it incurs additional debt to fund its capital spending and its acquisition of new assets and businesses. Kinder Morgan, Inc.’s interest expense was affected by reduced debt levels, primarily related to the application of the proceeds from the sale of an 80% interest in NGPL PipeCo LLC to reduce outstanding debt.

“Interest Expense, Net” for the seven months ended December 31, 2007 includes (i) $179.6 million of interest expense related to additional debt incurred as part of the going private transaction, (ii) $236.4 million of Kinder Morgan Energy Partners interest expense and (iii) $165.5 million of Kinder Morgan, Inc. interest expense not related to the going private transaction.

“Interest Expense, Net” for the five months ended May 31, 2007 includes (i) $155.0 million of Kinder Morgan Energy Partners interest expense and (ii) $86.1 million of Kinder Morgan, Inc. interest expense.

“Interest Expense, Net” for the year ended December 31, 2006 includes (i) $333.4 million of Kinder Morgan Energy Partners interest expense, (ii) $157.8 million of Kinder Morgan, Inc. interest expense and (iii) $67.8 million related to Terasen.

During the first quarter of 2006, we recorded a pre-tax charge of $22.3 million ($14.1 million after tax) related to the financing of the Terasen acquisition. The charge was necessary because certain hedges put in place related to the debt financing for the acquisition did not qualify for hedge treatment under GAAP, thus requiring that they be marked-to-market, resulting in a non-cash charge to income. These hedges have now been effectively terminated (see Note 15 of the accompanying Notes to Consolidated Financial Statements).

Net Income Attributable to Noncontrolling Interests

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Kinder Morgan Management	$	(80.5	)	$	(35.8	)	$	(17.1	)	$	(65.9	)
Kinder Morgan Energy Partners		(302.4	)		7.3			(75.1	)		(300.8	)
Triton		(13.0	)		(9.0	)		2.3			(7.3	)
Other		(0.2	)		(0.1	)		(0.8	)		(0.2	)
Net Income Attributable to Noncontrolling Interests	$	(396.1	)	$	(37.6	)	$	(90.7	)	$	(374.2	)

“Net Income Attributable to Noncontrolling Interests” associated with Kinder Morgan Management for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $80.5 million, $35.8 million, $17.1 million and $65.9 million, respectively. “Net Income Attributable to Noncontrolling Interests” reflects the earnings recorded by Kinder Morgan Management that are attributed to its shares held by the public. Kinder Morgan Management’s earnings are solely dependent on its ownership of Kinder Morgan Energy

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Partnership i-units. Therefore, the amount associated with Kinder Morgan Management is a function of Kinder Morgan Energy Partners’ earnings and the shares of Kinder Morgan Management, which are held by the public. As of December 31, 2008, December 31, 2007 and May 31, 2007 we owned approximately 14.3% of Kinder Morgan Managements’ outstanding shares. As of December 31, 2006 we owned approximately 16.5% of Kinder Morgan Managements’ outstanding shares.

“Net Income Attributable to Noncontrolling Interests” associated with Kinder Morgan Energy Partners for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $302.4 million, ($7.3) million, $75.1 million and $300.8 million, respectively. The amount reflects the earnings (loss) from continuing operations recorded by Kinder Morgan Energy Partners that are attributed to its units held by the public. During the seven months ended December 31, 2007, $141.6 million of the “Net Income Attributable to Noncontrolling Interests” associated with Kinder Morgan Energy Partners’ North System, which was sold by Kinder Morgan Energy Partners in October 2007, was recorded in discontinued operations. See Note 11 of the accompanying Notes to Consolidated Financial Statements.

Income Taxes—Continuing Operations

Year Ended December 31, 2008

The year ended December 31, 2008 income tax expense from continuing operations of $304.3 million consists of (i) $261.4 million of federal income tax expense, (ii) $44.9 million related to Kinder Morgan Management noncontrolling interest income tax expense, (iii) $11.7 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision, (iv) $22.2 million of prior period adjustments, (v) $17.0 million of state income taxes and (vi) $15.3 million of other income tax items. These income tax expenses were offset by $68.2 million benefit primarily due to the termination of certain of our subsidiaries’ presence in Canada, resulting in the elimination of future taxable gains and a reduction in Canadian foreign tax rates.

Seven Months Ended December 31, 2007

The seven months ended December 31, 2007 income tax expense from continuing operations of $227.4 million consists of (i) $166.5 million of federal income tax expense, (ii) $12.8 million related to Kinder Morgan Management noncontrolling interest income tax expense, (iii) $ 27.6 million due to income taxes on foreign earnings at different tax rates, (iv) $11.9 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (v) $10.9 million of state income taxes. The above income tax expense is net of $2.3 million of other income tax items.

Five Months Ended May 31, 2007

The five months ended May 31, 2007 income tax expense from continuing operations of $135.5 million consists of (i) $34.0 million federal income tax benefit on the $97.2 million loss from continuing operations before income taxes, (ii) $16.6 million tax benefit from the Terasen acquisition financing structure and (iii) $2.0 million of other income tax items. These tax benefits and credits were offset by income tax expenses consisting of (i) $30.7 million of income taxes on non-deductible fees associated with the Going Private transaction, (ii) $132.1 million of expense related to the Trans Mountain goodwill impairment of $377.1 million, which is not deductible for tax purposes, (iii) $6.2 million related to Kinder Morgan Management noncontrolling interest income tax expense, (iv) $8.4 million due to income taxes on foreign earnings at different tax rates, (v) $4.0 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (vi) $6.7 million of state income taxes.

Year Ended December 31, 2006

The year ended December 31, 2006 income tax expense from continuing operations of $285.9 million consists of (i) $309.8 million of federal income tax expense, (ii) $23.9 million related to Kinder Morgan Management noncontrolling interest income tax expense, (iii) $23.0 million due to income taxes on foreign earnings at different tax rates, (iv) $12.4 million attributable to the net tax effects of consolidating Kinder Morgan Energy Partners’ United States income tax provision and (v) $15.0 million of state income taxes. These income tax expenses were offset by the following tax benefits and credits: (i) a $45.1 million tax benefit from the Terasen acquisition financing structure, (ii) a $38.1 million tax benefit from a change in our deferred tax rates and (iii) a $15.0 million of other income tax items.

See Note 13 of the accompanying Notes to Consolidated Financial Statements for additional information on income taxes.

Income Taxes—Realization of Deferred Tax Assets

A capital loss carryforward can be utilized to reduce capital gain during the five years succeeding the year in which a capital loss is incurred. We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4

26

billion (C$3.7 billion) including cash and assumed debt. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of the Terasen Inc. capital loss was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations resulting in a tax benefit of approximately $82.2 million during 2007.

At December 31, 2007, we had a remaining capital loss carryforward of $775.1 million, all of which was utilized to reduce the capital gain associated with the sale of our 80% ownership interest in the NGPL business segment and other dispositions, resulting in a tax benefit of approximately $279.5 million during 2008.

Liquidity and Capital Resources

Liquidity

We believe that we and our subsidiaries and investments, including Kinder Morgan Energy Partners, have liquidity and access to financial resources as discussed below sufficient to meet future requirements for working capital, debt repayment and capital expenditures associated with existing and future expansion projects as follows:

· Cash flow from operations

Our diverse set of energy infrastructure assets generated $1,397.6 million of cash flows from continuing operations for the year ended December 31, 2008. Additionally, Kinder Morgan Energy Partners expansion projects in aggregate are expected to generate positive returns on our investment, based on long-term contracted customer commitments and our current estimated expansion project costs.

· Credit facility availability

As of December 31, 2008, Kinder Morgan, Inc. had available credit capacity of $929.2 million and Kinder Morgan Energy Partners had available credit capacity of $1,473.7 million after reduction for (i) our letters of credit, (ii) commercial paper outstanding (none at December 31, 2008) and (iii) lending commitments made by a Lehman Brothers related bank (see Customer and Capital Market Liquidity). Kinder Morgan Energy Partners’ joint venture projects, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC and Cortez Capital Corporation, have undrawn capacity of $366.6 million, $429.2 million and $9.0 million, respectively, under their separate credit facilities, net of Lehman Brothers’ commitments (see Customer and Capital Market Liquidity).

· Long-term debt and equity markets

During the year ended December 31, 2008, Kinder Morgan Energy Partners, for itself and for its equity investment, Rockies Express Pipeline LLC, collectively has raised $3.4 billion of long-term debt and $676.9 million of equity through the issuance of Kinder Morgan Energy Partners units. Including the quarterly share distributions paid by Kinder Morgan Management in 2008, which essentially constitute an automatic distribution re-investment program, a total of approximately $966.5 million in equity was raised during this timeframe.

· Kinder Morgan Energy Partners equity infusion

Additionally, in October 2008, our board of directors indicated Kinder Morgan, Inc’s willingness to purchase up to $750 million of Kinder Morgan Energy Partners equity over the next 15 months, if necessary, to support its capital raising efforts.

· Credit Ratings

On October 13, 2008, Standard and Poor’s Rating Services revised its outlook on Kinder Morgan Energy Partners’ long-term credit rating to negative from stable (but affirmed Kinder Morgan Energy Partners’ long-term credit rating at BBB), due to Kinder Morgan Energy Partners’ previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, Standard and Poor’s Rating Services lowered Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation are unable to access commercial paper borrowings. However, Kinder Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation expect that short-term financing and liquidity needs will continue to be met through borrowings made under their respective bank credit facilities. Kinder Morgan, Inc.’s Standard and Poor’s Rating Services credit rating has not changed in the year ended December 31, 2008 and remains BB on its secured senior debt.

Customer and Capital Market Liquidity

Some of Kinder Morgan Energy Partners’ customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. These financial problems may arise from the current credit market crisis, changes in commodity prices or otherwise. Kinder Morgan Energy Partners is 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 their credit position relating to amounts owed from these customers. Kinder Morgan, Inc. and Kinder Morgan Energy Partners cannot provide assurance that one or more of Kinder Morgan Energy

27

Partners’ financially distressed customers will not default on their obligations to them or that such a default or defaults will not have a material adverse effect on Kinder Morgan Energy Partners’ business, or Kinder Morgan, Inc.’s financial position, future results of operations, or future cash flows; however, Kinder Morgan, Inc. believes it has recorded adequate allowances for such customers.

On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided a portion of Kinder Morgan Energy Partners’, Rockies Express Pipeline LLC’s and Midcontinent Express Pipeline LLC’s respective credit facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is party to the credit facilities, has not met its obligations to lend under those agreements. As such, the commitments have been effectively reduced by $63 million, $41 million and $100 million, respectively, to $1.8 billion, $2.0 billion and $1.3 billion. The commitments of the other banks remain unchanged, and the facilities are not defaulted.

Invested Capital

Our net debt (outstanding notes and debentures plus short-term debt, less cash and cash equivalents) to total capital, excluding accumulated other comprehensive income, for the years ended December 31, 2008 and 2007 was 56.4% and 56.9%, respectively. Our net debt to total capital ratio was principally impacted by debt reductions made possible by $5.9 billion in total proceeds related to the sale of an 80% ownership interest in NGPL PipeCo LLC, which proceeds were used to pay off the entire outstanding balances of our senior secured credit facility’s Tranche A and Tranche B term loans (approximately $4.2 billion), to repurchase $1.67 billion par value of our outstanding debt securities and to reduce borrowings outstanding under our $1.0 billion revolving credit facility. This increase was partially offset by a $4.03 billion non-cash goodwill impairment charge associated with the Going Private transaction (see Note 3 of the accompanying Notes to Consolidated Financial Statements) as well as $2.1 billion in additional borrowings by Kinder Morgan Energy Partners during 2008.

In addition to the direct sources of debt and equity financing, we obtain financing indirectly through our ownership interests in unconsolidated entities as discussed in Note 18 of the accompanying Notes to Consolidated Financial Statements. In addition to our results of operations, these balances are affected by our financing activities as discussed following.

Except for Kinder Morgan Energy Partners and its subsidiaries, we employ a centralized cash management program that essentially concentrates the cash assets of our subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. Our centralized cash management program provides that funds in excess of the daily needs of our subsidiaries be concentrated, consolidated, or otherwise made available for use by other entities within our consolidated group. We place no restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to parent companies other than restrictions that may be contained in agreements governing the indebtedness of those entities; provided that neither we nor our subsidiaries (other than Kinder Morgan Energy Partners and its subsidiaries) have rights with respect to the cash of Kinder Morgan Energy Partners or its subsidiaries except as permitted by Kinder Morgan Energy Partners’ partnership agreement.

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

Short-term Liquidity

Our principal sources of short-term liquidity are our revolving bank facilities and cash provided by operations. The following represents the revolving credit facilities that were available to Kinder Morgan, Inc. and its respective subsidiaries, short-term debt outstanding under the credit facilities and available borrowing capacity under the facilities after applicable letters of credit.

	At December 31, 2008				At February 23, 2009
	Short-term Debt Outstanding		Available Borrowing Capacity		Short-term Debt Outstanding		Available Borrowing Capacity
	(In millions)
Credit Facilities
Kinder Morgan, Inc.
$1.0 billion, six-year secured revolver, due May 2013	$	8.8	$	929.2	$	23.0	$	914.1
Kinder Morgan Energy Partners
$1.85 billion, five-year unsecured revolver, due August 2010	$	-	$	1,473.7	$	527.6	$	1,022.4

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These facilities can be used for the respective entity’s general corporate or partnership purposes. Kinder Morgan Energy Partners’ facility is also used as backup for its commercial paper program. These facilities include financial covenants and events of default that are common in such arrangements. The terms of these credit facilities are discussed in Note 14 of the accompanying Notes to Consolidated Financial Statements.

Our current maturities of long-term debt of $293.7 million at December 31, 2008 represent (i) $250 million in principal amount of Kinder Morgan Energy Partners’ 6.30% senior notes due February 1, 2009, (ii) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds), (iii) $5.0 million of our 6.50% Series Debentures due September 1, 2013, (iv) $8.5 million of a 5.40% long-term note of Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company due March 31, 2009 and (v) $6.5 million of Kinder Morgan Texas Pipeline, L.P.’s 5.23% Series Notes due January 2, 2014. Apart from our notes payable, current maturities of long-term debt, and the fair value of derivative instruments, our current liabilities, net of our current assets, represent an additional short-term obligation of $380.7 million at December 31, 2008. Given our expected cash flows from operations, our unused debt capacity as discussed preceding, including our credit facilities, and based on our projected cash needs in the near term, we do not expect any liquidity issues to arise.

Significant Financing Transactions

For additional information on significant financing Transactions, see Note 14 of the accompanying Notes to Consolidated Financial Statements.

During 2008, we used the proceeds from the completed sale of an 80% ownership interest in our NGPL business segment to repurchase $1.67 billion par value debt securities and to pay off the balances of our Tranche A and Tranche B term loans, and amounts outstanding, at the time, of our $1.0 billion revolving credit facility totaling approximately $4.6 billion. In June 2007, we repaid the outstanding borrowings under the Tranche C term facility.

Kinder Morgan Energy Partners completed three offerings of senior notes during the year ended December 31, 2008, two offerings during the seven months ended December 31, 2007 and one offering during the five months ended May 31, 2007, raising a total (net of underwriting discounts and commissions) of $2,080.2 million, $1,041.7 million and $992.8 million, respectively. During the seven months ended December 31, 2007, Kinder Morgan Energy Partners also repaid $250 million of senior notes. Kinder Morgan Energy Partners used the proceeds from each of the three 2007 debt offerings and from the first two 2008 debt offerings to reduce the borrowings under Kinder Morgan Energy Partners’ commercial paper program. Kinder Morgan Energy Partners used the proceeds from its December 2008 debt offering to reduce the borrowings under its credit facility.

Kinder Morgan Energy Partners completed four offerings of common units during the year ended December 31, 2008, which raised a total of $676.9 million, net of underwriting discounts and commissions. For the seven months ended December 31, 2007 and five months ended May 31, 2007, Kinder Morgan Energy Partners raised a total (net of underwriting costs and commissions) of $342.9 million and $297.9 million, respectively, from the issuance of common units. Proceeds from these issuances were used to reduce borrowings under the commercial paper program and bank credit facility.

On July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057 to a single purchaser. We used the net proceeds of approximately $98.6 million after the initial purchaser’s discounts and commissions to reduce debt.

As discussed in Note 11 of the accompany Notes to Consolidated Financial Statements, on March 5, 2007 we entered into a definitive agreement to sell Terasen Pipelines (Corridor) Inc. and on February 26, 2007, we entered into a definitive agreement to sell Terasen Inc., which includes the assets of Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. These transactions closed on June 15, 2007 and May 17, 2007, respectively. Our consolidated debt was reduced by the debt balances of Terasen Inc. and Terasen Pipelines (Corridor) Inc. of approximately $2.9 billion, including the Capital Securities, as a result of these sales transactions. For the period from January 1, 2007 to May 17, 2007, average borrowings under Terasen Gas Vancouver Island Inc.’s C$350 million credit facility were $255.1 million at a weighted-average rate of 4.43%. For the period from January 1, 2007 to May 17, 2007, average borrowings under the C$20 million demand facility were $3.3 million at a weighted-average rate of 5.31%.

On May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, completed the Going Private transaction. In conjunction with the Going Private transaction, Kinder Morgan, Inc. entered into a $5.755 billion credit agreement dated May 30, 2007, which included three term credit facilities, which were subsequently retired, and one revolving credit facility. See Notes 1 and 14 of the accompanying Notes to Consolidated Financial Statements for additional information related to the Going Private transaction and the associated debt and debt retirement.

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On May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at 101.39% of the face amount. We recorded a pre-tax loss of $4.2 million in connection with this early extinguishment of debt.

Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that Kinder Morgan Energy Partners did not already own (see Note 10 of the accompanying Notes to Consolidated Financial Statements). As part of Kinder Morgan Energy Partners’ purchase price, two of its subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. Kinder Morgan Energy Partners’ subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company, are the obligors on the note and, as of December 31, 2008, the outstanding balance under the note was $36.6 million.

Capital Expenditures

Our sustaining capital expenditures for the year ended December 31, 2008 were $183.9 million, and we expect to spend $203.4 million during 2009. Our sustaining capital expenditures are funded with cash flows from operations.

Our expansion capital expenditures for the year ended December 31, 2008 were $2,361.4 million, primarily related to Kinder Morgan Energy Partners. Kinder Morgan Energy Partners expects to spend another $1,188.2 million during 2009. In addition to these amounts, Kinder Morgan Energy Partners contributed an aggregate amount of $333.5 million for both the Rockies Express and Midcontinent Express natural gas pipeline projects in 2008, and it expects to contribute, based on Kinder Morgan Energy Partners’ proportionate share of equity ownership interest in both projects, approximately $1.5 billion in the aggregate for both projects in 2009. Kinder Morgan Energy Partners will fund its 2009 capital expenditures and equity contributions through borrowings under its $1.85 billion revolving credit facility, proceeds from issuance of long term notes and common unit offerings.

Off Balance Sheet Arrangements

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

Entity	Investment Type	Our Ownership Interest	Remaining Interest(s) Ownership	Total Entity Assets			Total Entity Debt			Our Contingent Share of Entity Debt
Cortez Pipeline Company	General Partner	50%	1	$	95.7	2	$	169.6		$	84.8	3
West2East Pipeline LLC4	Limited Liability	51%	ConocoPhillips and Sempra Energy	$	4,787.0	2	$	3,458.9	5	$	1,102.1	6
Midcontinent Express Pipeline LLC7	Limited Liability	50%	Energy Transfer Partners, L.P.	$	998.5	2	$	837.5		$	418.8	8
Nassau County, Florida Ocean Highway And Port Authority9	N/A	N/A	Nassau County, Florida Ocean Highway and Port Authority		N/A			N/A		$	10.2
NGPL PipeCo LLC	Equity	20%	Myria Acquisition Inc.	$	7,064.5		$	3,000.0		$	-	10

_________

1 The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly owned subsidiary of Exxon Mobil Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.

2 Principally property, plant and equipment.

3 We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt. As of December 31, 2008, Shell Oil Company shares Kinder Morgan Energy Partners’ several guaranty obligations jointly and severally for $53.6 million of Cortez Pipeline Company’s debt balance; however, Kinder Morgan Energy Partners is obligated to indemnify Shell Oil Company for the liabilities Shell Oil Company incurs in connection with such guaranty. Accordingly, as of December 31, 2008 Kinder Morgan Energy Partners has a letter of credit in the amount of $26.8 million issued by JP Morgan Chase, in order to secure its indemnification obligations to Shell Oil Company for 50% of the Cortez Pipeline Company debt balance of $53.6 million.

Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital

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Corporation. The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline Company owners under this agreement.

4 West2East Pipeline LLC is a limited liability company and is the sole owner of Rockies Express Pipeline LLC. As of December 31, 2008, the remaining limited liability member interests in West2East Pipeline LLC are owned by ConocoPhillips (24%) and Sempra Energy (25%). Kinder Morgan Energy Partners owned a 66 2/3% ownership interest in West2East Pipeline LLC from October 21, 2005 until June 30, 2006, and included West2East Pipeline LLC’s results in its consolidated financial statements until June 30, 2006. On June 30, 2006, Kinder Morgan Energy Partners’ ownership interest was reduced to 51%, West2East Pipeline LLC was deconsolidated, and Kinder Morgan Energy Partners subsequently accounted for its investment under the equity method of accounting. Upon completion of the pipeline, Kinder Morgan Energy Partners’ ownership percentage is expected to be reduced to 50%.

5 Amount includes an aggregate of $1.3 billion in principal amount of fixed rate senior notes issued by Rockies Express Pipeline LLC in a private offering in June 2008. All payments of principal and interest in respect of these senior notes are the sole obligation of Rockies Express Pipeline LLC. Noteholders have no recourse against Kinder Morgan Energy Partners or the other member owners of West2East Pipeline LLC for any failure by Rockies Express Pipeline LLC to perform or comply with its obligations pursuant to the notes or the indenture.

6 In addition, there is a letter of credit outstanding to support the construction of the Rockies Express Pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of the total face amount).

7 Midcontinent Express Pipeline LLC is a limited liability company and the owner of the Midcontinent Express Pipeline. In January 2008, in conjunction with the signing of additional binding pipeline transportation commitments, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement that provides MarkWest Pioneer, L.L.C.  a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline is fully constructed and placed into service. If the option is exercised, Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest Pioneer, L.L.C. will own the remaining 10%.

8 In addition, there is a letter of credit outstanding to support the construction of the Midcontinent Express Pipeline. As of December 31, 2008, this letter of credit, issued by the Royal Bank of Scotland plc, had a face amount of $33.3 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of the total face amount).

9 This arrangement rose from Kinder Morgan Energy Partners’ Vopak terminal acquisition in July 2001. Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals LLC, the operator of the port facilities. In July 2002, Kinder Morgan Energy Partners acquired Nassau Terminals LLC and became guarantor under the letter of credit agreement. In December 2002, Kinder Morgan Energy Partners issued a $28 million letter of credit under its credit facilities and the former letter of credit guarantee was terminated. As of December 31, 2008, the face amount of this letter of credit outstanding under Kinder Morgan Energy Partners’ credit facility was $10.2 million. Principal payments on the bonds are made on the first of December each year at which time reductions are made to the letter of credit.

10 Debtors have recourse only to the assets of the entity, not the owners.

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Aggregate Contractual Obligations

Aggregate Contractual Obligations

At December 31, 2008

	Total		Less than 1 year		2-3 years		4-5 years		After 5 years
	(In millions)
Contractual Obligations
Short-term Borrowings	$	8.8	$	8.8	$	-	$	-	$	-
Long-term Debt, Including Current Maturities:
Principal Payments		11,514.5		293.7		1,743.8		2,814.8		6,662.2
Interest Payments1		9,252.5		717.5		1,349.4		1,062.4		6,123.2
Lease Obligations2,3		664.7		57.5		103.4		85.4		418.4
Pension and Postretirement Benefit Plans		90.5		25.1		10.7		12.2		42.5
Other Obligations6		15.1		8.3		6.8		-		-
Total Contractual Cash Obligations4	$	21,546.1	$	1,110.9	$	3,214.1	$	3,974.8	$	13,246.3
Other Commercial Commitments
Standby Letters of Credit5	$	405.8	$	335.3	$	25.7	$	26.8	$	18.0
Capital Expenditures7	$	581.0	$	581.0	$	-	$	-	$	-

____________

1 Interest payments have not been adjusted for any amounts receivable related to our interest rate swaps outstanding. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

2 Represents commitments for operating leases.

3 Approximately $437.6 million, $20.6 million, $41.4 million, $40.7 million and $334.9 million in each respective column is attributable to the lease obligation associated with the Jackson, Michigan power generation facility.

4 As of December 31, 2008, the liability for uncertain income tax positions, excluding associated interest and penalties, was $26.2 million pursuant to FASB Interpretation No. 48. This liability represents an estimate of tax positions that we have taken in our tax returns, which may ultimately not be sustained upon examination by the tax authorities. Since the ultimate amount and timing of any future cash settlements cannot be predicted with reasonable certainty, this estimated liability has been excluded from the Aggregate Contractual Obligations.

5 See Note 18 of the accompanying Notes to Consolidated Financial Statements for a listing of letters of credit outstanding as of December 31, 2008.

6 Consists of payments due under carbon dioxide take-or-pay contracts and, for the 1 Year or Less column only, Kinder Morgan Energy Partners’ purchase and sale agreement with LPC Packaging (a California corporation) for the acquisition of certain bulk terminal assets.

7 Represents commitments for the purchase of property, plant and equipment at December 31, 2008.

We expect to have sufficient liquidity to satisfy our near-term obligations through the combination of free cash flow and our credit facilities, including those of Kinder Morgan Energy Partners.

Contingent Liabilities:	Contingency	Amount of Contingent Liability at December 31, 2008
Guarantor of the Bushton Gas Processing Plant Lease1	Default by ONEOK, Inc.	Total $78.8 million; Averages $26.3 million per year through 2011
Jackson, Michigan Power Plant Incremental Investment	Operational Performance	$3 to $8 million per year for 10 years
Jackson, Michigan Power Plant Incremental Investment	Cash Flow Performance	Up to a total of $25 million beginning in 2018

____________

1 In conjunction with our sale of the Bushton gas processing facility to ONEOK, Inc., at December 31, 1999, ONEOK, Inc. became primarily liable under the associated operating lease and we became secondarily liable. Should ONEOK, Inc. fail to make payments as required under the lease, we would be required to make such payments, with recourse only to ONEOK, Inc.

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Investment in Kinder Morgan Energy Partners

At December 31, 2008, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 32.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 16.4 million common units, 5.3 million Class B units and 11.1 million i-units, represent approximately 12.3% of the total limited partner interests of Kinder Morgan Energy Partners. In addition, we are the sole common stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 14.1% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2008. As of the close of the Going Private transaction, our limited partner interests and our general partner interest represented an approximate 50% economic interest in Kinder Morgan Energy Partners. This difference results from the existence of incentive distribution rights held by the general partner shareholder.

Cash Flows

The following discussion of cash flows should be read in conjunction with the accompanying Consolidated Statements of Cash Flows and related supplemental disclosures. The following discussion is an analysis of the cash flows for the year ended December 31, 2008 and seven months ended December 31, 2007 (both successor basis) and the five months ended May 31, 2007 and year ended December 31, 2006 (both predecessor basis). All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents.

The following table summarizes our net cash flows from operating, investing and financing activities for each period presented.

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Net Cash Provided by (Used in)
Operating Activities	$	1,396.8		$	1,044.5		$	603.0		$	1,707.3
Investing Activities		3,210.0			(15,751.1	)		723.7			(1,795.9	)
Financing Activities		(4,628.1	)		12,956.8			440.9			88.7
Effect of Exchange Rate Changes on Cash		(8.7	)		(2.8	)		7.6			6.6
Effect of Accounting Change on Cash		-			-			-			12.1
Cash Balance Included in Assets Held for Sale		-			(1.1	)		(2.7	)		(5.6	)
Net (Decrease) Increase in Cash and Cash Equivalents	$	(30.0	)	$	(1,753.7	)	$	1,772.5		$	13.2

Year Ended December 31, 2008

Net cash flows from operating activities during the period were positively affected by (i) net income of $1,076.4 million, after adjustments for non-cash items including, among other things, a $4.0 billion goodwill impairment charge and $16.5 million of Kinder Morgan Energy Partners’ rate reserve adjustments, (ii) $192.0 million of net proceeds received for the early termination of interest rate swap agreements, primarily relating to agreements associated with Kinder Morgan Energy Partners and (iii) distributions received from equity investments of $241.6 million, comprised mainly of (a) $82.9 million of initial distributions received from West2East Pipeline LLC, (b) $43.0 million from Kinder Morgan Energy Partners’ investment in the Express pipeline system, (c) $40.1 million from NGPL PipeCo LLC and (d) $33.3 million from Kinder Morgan Energy Partners’ investment in Red Cedar Gathering Company.

Partially offsetting these cash inflows were (i) a $44.9 million use of cash for working capital items, primarily resulting from income tax payments made during the period related to our ongoing operations and the sale of an 80% ownership interest in NGPL PipeCo LLC, (ii) $30.2 million of FERC-mandated reparation payments to certain Kinder Morgan Energy Partners’ Pacific operations’ pipelines for settlements reached with certain shippers on its East Line pipeline and (iii) a $28.0 million increase of gas in underground storage. Significant period-to period variations in cash used or generated from gas in storage transactions are generally due to changes in injection and withdrawal volumes as well as fluctuations in natural gas prices.

Net cash flows from investing activities during the period were positively affected by (i) net proceeds of $2,899.3 million from the sale of an 80% ownership interest in NGPL PipeCo LLC, (ii) $3,106.4 million of proceeds received from NGPL PipeCo LLC restricted cash upon the sale to Myria (including approximately $110.0 million we escrowed at the time of the

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bond closing), (iii) return of capital from equity investments of $98.1 million consisting of $89.1 million and $9.0 million from Midcontinent Express Pipeline LLC and NGPL PipeCo LLC, respectively, (iv) net proceeds received of $111.1 million for the sale of other assets and (v) a $71.0 million decrease in margin deposits.

These positive impacts were partially offset by (i) capital expenditures of $2,545.3 million, primarily from Kinder Morgan Energy Partners’ natural gas pipeline projects, including the construction of Kinder Morgan Louisiana Pipeline, the expansion of the Trans Mountain crude oil and refined petroleum products pipeline system and additions to Kinder Morgan Energy Partners’ carbon dioxide producing and delivery operations, (ii) incremental contributions to equity investments of $366.2 million, consisting primarily of (a) a $306.0 million contribution to West2East Pipeline LLC made in February 2008 and (b) contributions of $27.5 million for Kinder Morgan Energy Partners’ share of Midcontinent Express Pipeline LLC construction costs, (iii) a $109.6 million loan to a single customer within Kinder Morgan Energy Partners’ Texas Intrastate Natural Gas Pipeline Group, (iv) acquisitions of $47.6 million and (v) a $7.2 million increase in underground natural gas storage volumes during the period.

Net cash flows used in financing activities during the period were affected by (i) a use of cash of $5,805.4 million for the retirement of long-term debt, primarily for (a) $1.6 billion for a cash tender offer to purchase a portion of our outstanding long-term debt, (b) a $997.5 million use of cash for the retirement of our Tranche A term loan facilities and (c) a $3,191.8 million use of cash for the retirement of our Tranche B term loan facilities, (ii) a net $879.2 million decrease in short-term borrowings relating to our and Kinder Morgan Energy Partners’ credit facilities and (iii) noncontrolling interests distributions of $630.3 million, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders.

The impact of these factors were partially offset by (i) net proceeds of $2,097.3 million from Kinder Morgan Energy Partners’ debt issuances, (ii) noncontrolling interests contributions of $561.5 million, primarily from Kinder Morgan Energy Partners’ issuance of common units from its first and fourth quarter 2008 public offerings, (iii) an increase in cash book overdrafts of $14.5 million and (iv) a $2.7 million increase in short-term advances from unconsolidated affiliates.

Seven Months Ended December 31, 2007

Net cash flows from operating activities during the period were positively impacted by (i) net income of $762.3 million after adjustments for non-cash items including, among other things, Kinder Morgan Energy Partners’ reparations and reserve adjustments of $140.0 million, (ii) a $104.0 million source of cash for working capital items, (iii) $86.5 million of distributions received from equity investments, (iv) a $51.3 million decrease of gas in underground storage and (v) $49.1 million of payments received from Kinder Morgan Energy Partners’ pipeline customers for future service.

Partially offsetting these factors were (i) a $3.2 million use of cash attributable to discontinued operations and (ii) a $2.2 million payment for the termination of interest rate swap agreements.

Net cash flows used in investing activities during the period were affected by (i) $11,534.3 million of cash used to purchase Kinder Morgan, Inc. stock in the Going Private transaction, (ii) $3,030.0 million of cash used to invest in NGPL PipeCo LLC restricted deposits, (iii) $1,287.0 million in capital expenditures primarily attributable to Kinder Morgan Energy Partners, (iv) $122.0 million of other acquisitions, (v) incremental margin deposits of $39.3 million and (vi) contributions of $246.4 million to equity investments.

These negative impacts were partially offset by (i) $196.6 million of cash provided by discontinued investing activities, primarily from the sale of Corridor, (ii) $301.3 million of net proceeds from the sale of other assets, primarily from the sale of Kinder Morgan Energy Partners’ North System operations and (iii) $10.0 million of proceeds received from the sale of underground natural gas storage volumes.

Net cash flows provided by financing activities during the period were principally due to (i) $5,112.0 million of equity contributions from investors in the Going Private transaction, (ii) $4,696.2 million of proceeds, net of issuance costs, received from the issuance of senior secured credit facilities to partially finance the Going Private transaction, (iii) $2,986.3 million of net proceeds from NGPL PipeCo LLC’s issuance of senior notes, (iv) $1,041.7 million of net proceeds from Kinder Morgan Energy Partners’ public debt offerings, (v) $342.9 million of contributions from noncontrolling interest owners attributable to Kinder Morgan Energy Partners’ issuance of 7.13 million common units and (vi) $98.6 million of net proceeds from Kinder Morgan G.P., Inc.’s Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock.

The impact of these factors was partially offset by (i) a $455 million use of cash for the retirement of our senior secured Tranche C term loan facility, (ii) a $250 million use of cash for a required payment on senior notes of Kinder Morgan Energy Partners, (iii) a $110.75 million use of cash for (a) quarterly payments of $2.5 million on our Tranche A and $8.25 million on our Tranche B term loan facilities and (b) a $100 million voluntary payment on our Tranche B term loan facility, (iv) $181.1 million of cash paid to share-based award holders due to the Going Private transaction, (v) noncontrolling interests distributions of $259.6 million, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (vi) a net decrease of $52.6 million in short-term debt and (vii) a decrease of $14.0 million in cash book overdrafts.

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Five months Ended May 31, 2007

Net cash flows from operating activities during the period were positively affected by (i) net income of $688.2 million, after adjustments for non-cash items, (ii) $109.8 of cash provided by discontinued operations, (iii) net proceeds of $51.9 million from the termination of interest rate swaps and (iv) $48.2 million of distributions from equity investments.

These positive factors were partially offset by (i) a use of cash of $202.9 million for working capital items and (ii) an $84.2 million increase in gas in underground storage.

Net cash flows from investing activities during the period were positively impacted by (i) $1,488.2 million of cash from discontinued investing activities, primarily from the sales of our discontinued Terasen and U.S.-based retail operations, (ii) $8.4 million of proceeds received from the sale of underground natural gas storage volumes and (iii) $8.0 million of cash received for property casualty indemnifications.

Partially offsetting these factors were (i) $652.8 million of capital expenditures, (ii) a $54.8 million use of cash for margin deposits, (iii) incremental acquisitions of $42.1 million and (iv) $29.7 million of contributions to equity investments.

Net cash flows from financing activities during the period were positively impacted by (i) $992.8 million of net proceeds from Kinder Morgan Energy Partners’ public debt offerings, (ii) $297.9 million of proceeds from the issuance of Kinder Morgan Management shares, (iii) $140.1 million of cash provided from discontinued financing activities, (iii) $56.7 million of cash received for excess tax benefits from share-based payment arrangements and (iv) $9.9 million of proceeds received from the issuance of our predecessor’s common stock.

The impact of these positive factors was partially offset by (i) a $304.2 million use of cash for the early retirement of a portion of our senior notes, (ii) $248.9 million of noncontrolling interests distributions, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (iii) a net decrease of $247.5 million in short-term debt, (iii) $234.9 million paid for dividends on our predecessor’s common stock and (iv) a decrease of $14.9 million in cash book overdrafts.

Year Ended December 31, 2006

Net cash flows from operating activities during the period were positively affected by (i) net income of $1,425.7 million, after adjustments for non-cash items, (ii) $212.6 of cash provided by discontinued operations, (iii) an $80.0 million source of cash for working capital items and (iv) $74.8 million of distributions from equity investments.

These positive factors were partially offset by (i) a $35.3 million increase in gas in underground storage and (ii) $19.1 million of payments made to certain shippers on Kinder Morgan Energy Partners’ West Coast Products Pipelines as a result of a settlement agreement regarding delivery tariffs and gathering enhancement fees at its Watson Station.

Net cash flows used in investing activities during the period were affected by (i) $1,375.6 million in capital expenditures, (ii) $407.1 million of acquisitions, (iii) $251.0 million of cash used for discontinued investing activities, primarily attributable to Terasen’s capital expenditures, (iv) $12.9 million for investments in underground storage volumes and payments made for natural gas liquids line-fill and (v) contributions of $6.1 million to equity investments.

These negative impacts were partially offset by (i) $112.9 million of proceeds received for the sale of Terasen’s discontinued Water and Utility Services, (ii) $92.2 million of net proceeds from the sale of other assets, (iii) $38.6 million of net proceeds from the sale of margin deposits and (iv) $13.1 million of cash received for property casualty indemnifications.

Net cash flows from financing activities during the period were positively impacted by (i) a net increase of $1,009.5 million in short-term debt, (ii) $353.8 million of contributions from noncontrolling owners, primarily Kinder Morgan Energy Partners’ issuance of 5.75 million common units receiving net proceeds (after underwriting discount) of $248.0 million and Sempra Energy’s $104.2 million contribution for its 33 1/3 % share of the purchase price of Entrega Pipeline LLC, (iii) $38.7 million of proceeds received from the issuance of our predecessor’s common stock, (iv) $18.6 million of cash received for excess tax benefits from share-based payment arrangements and (v) an increase of $17.9 million in cash book overdrafts.

The impact of these positive factors was partially offset by (i) $575.0 million of noncontrolling interests distributions, primarily resulting from Kinder Morgan Energy Partners’ distributions to common unit holders, (ii) $468.5 million paid for dividends on our predecessor’s common stock, (iii) $125.0 million of cash used to retire our 7.35% Series debentures which were elected by the holders to be redeemed on August 1, 2006 as provided in the indenture governing the debentures, (iv) a $118.1 million use of cash related to our discontinued Terasen financing activities, (v) $34.3 million in cash paid to repurchase our predecessor’s common shares and (vi) a $4.9 million use of cash for short-term advances to unconsolidated affiliates.

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Noncontrolling Interests Distributions to Kinder Morgan Energy Partners’ Common Unit Holders

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

Kinder Morgan Management, as the delegate of Kinder Morgan G.P., Inc., of which we indirectly own all of the outstanding common equity, and the general partner of Kinder Morgan Energy Partners, is granted discretion to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Kinder Morgan Management determines Kinder Morgan Energy Partners’ quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to Kinder Morgan Energy Partners’ limited partners with 2% retained by Kinder Morgan G.P., Inc. as Kinder Morgan Energy Partners’ general partner. These distribution percentages are modified to provide for incentive distributions to be retained by Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners in the event that quarterly distributions to unitholders exceed certain specified targets.

Available cash for each quarter is distributed:

· first, 98% to the owners of all classes of units pro rata and 2% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;

· second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;

· third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and

· fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units in cash and to Kinder Morgan Management as owners of i-units in the equivalent number of i-units, and 50% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy Partners.

During the year ended December 31, 2008, Kinder Morgan Energy Partners paid distributions of $3.89 per common unit, of which $626.6 million was paid to the public holders (represented in noncontrolling interests) of Kinder Morgan Energy Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners declared a quarterly distribution of $1.05 per common unit for the quarterly period ended December 31, 2008. The distribution was paid on February 13, 2009, to unitholders of record as of January 30, 2009.

Fair Value Measurement

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

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

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certain physical contracts.

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

	Significant Unobservable Inputs (Level 3)
	Assets							Liabilities
	December 31, 2008		December 31, 2007		Change			December 31, 2008			December 31, 2007			Change
WTI Options	$	34.3	$	—	$	34.3		$	(2.2	)	$	—		$	(2.2	)
WTS Oil Swaps		17.1		—		17.1			(0.2	)		(94.5	)		94.3
Natural Gas Basis Swaps		3.3		2.8		0.5			(5.2	)		(4.7	)		(0.5	)
Natural Gas Options		—		—		—			(2.7	)		—			(2.7	)
Other		0.5		1.0		(0.5	)		(0.8	)		(4.9	)		4.1
Total	$	55.2	$	3.8	$	51.4		$	(11.1	)	$	(104.1	)	$	93.0

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

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

· Option contracts—valued using internal model. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes;

· WTS oil swaps—prices obtained from a broker using their proprietary model for similar assets and liabilities (quotes are non-binding); and

· Natural gas basis swaps—values obtained through a pricing service, derived by combining raw inputs from the New York Mercantile Exchange (referred to in this report as NYMEX) with proprietary quantitative models and processes. Although the prices are originating from a liquid market (NYMEX), we believe the incremental effort to further validate these prices would take undue effort and would not materially alter the assumptions. As a result, we have classified the valuation of these derivatives as Level 3.

For our energy commodity derivative contracts, the most observable inputs available are used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, we use broker quotes for identical or similar contracts, or internally prepared valuation models as primary inputs to determine fair value. No adjustments were made to quotes or prices obtained from brokers and pricing services, and our valuation methods have not changed during the year ended December 31, 2008.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence, including but not limited to our credit default swap quotes as of December 31, 2008. Collateral agreements with our counterparties serve to reduce our credit exposure and are considered in the adjustment. We adjust the fair value measurements of our energy commodity derivative contracts for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the net assets balance associated with these contracts recorded in the accompanying Consolidated Balance Sheet included a reduction of $2.2 million related to discounting the value of our energy commodity derivative net assets for the effect of credit risk.

With the exception of the Casper and Douglas natural gas processing plant hedges and the ineffective portion of our derivative contracts, our energy commodity derivative contracts are accounted for as cash flow hedges. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments (“SFAS No. 133”), gains and losses associated with cash flow hedges are reported in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets.

Litigation and Environmental Matters

As of December 31, 2008, we have recorded a total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, in the amount of $85.0 million. In addition, we have recorded a receivable of $20.9 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

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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. As of December 31, 2007, our total reserve for environmental claims, without discounting and without regard to anticipated insurance recoveries, amounted to $102.6 million.

Additionally, as of December 31, 2008, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million. The reserve is primarily related to various claims from lawsuits arising from Kinder Morgan Energy Partners’ West Coast Products Pipelines, and the recorded amount is based on both the estimated amount associated with possible outcomes and probabilities of occurrence associated with such outcomes. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision. As of December 31, 2007, our total reserve for legal fees, transportation rate cases and other litigation liabilities amounted to $249.4 million.

Though no assurance can be given, we believe we have established adequate environmental and legal reserves such that the resolution of pending environmental matters and litigation will not have a material adverse impact on our business, cash flows, financial position or results of operations. 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 Note 21 of the accompanying Notes to Consolidated Financial Statements for additional information regarding pending litigation and environmental matters.

Regulation

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

Please refer to Note 20 of the accompanying Notes to Consolidated Financial Statements for additional information regarding regulatory matters.

Recent Accounting Pronouncements

Refer to Note 22 of the accompanying Notes to Consolidated Financial Statements for information regarding recent accounting pronouncements.

Information Regarding Forward-looking Statements

This filing includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to service debt or to pay dividends 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

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control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:

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

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

· changes in tariff rates charged by our or those of Kinder Morgan Energy Partners’ pipeline subsidiaries implemented by the Federal Energy Regulatory Commission, or other regulatory agencies 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 the ability to expand our facilities;

· difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from Kinder Morgan Energy Partners’ 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 or Kinder Morgan Energy Partners serve, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains and the Alberta oil sands;

· changes in laws or regulations, third-party relations and approvals and decisions of courts, regulators and governmental bodies that may adversely affect our business or 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 Kinder Morgan Energy Partners’ ability to offer and sell equity securities and its ability to sell debt securities or obtain debt financing in sufficient amounts to implement that portion of our or Kinder Morgan Energy Partners’ business plans that contemplates growth through acquisitions of operating businesses and assets and expansions of facilities;

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

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

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

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

· capital and credit markets conditions, including availability of credit generally, as well as inflation and interest rates;

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

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

· our ability to achieve cost savings and revenue growth;

· foreign exchange fluctuations;

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

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

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

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

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

· the timing and success of Kinder Morgan Energy Partners’ and our business development efforts; and

· unfavorable results of litigation and the fruition of contingencies referred to in the accompanying Notes to Consolidated Financial Statements.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements. See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Other than as required by

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

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

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

Energy Commodity Market Risk

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

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

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

	Credit Rating
Citigroup	A
J. Aron & Company / Goldman Sachs	A
Morgan Stanley	A

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

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

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

The accumulated components of other comprehensive income are to be reported separately as accumulated other comprehensive income or loss in the stockholders’ equity section of the balance sheet. For us, the amounts included in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets primarily include (i) the effective portion of the gains and losses on cash flow hedging items, (ii) gains and losses and prior service costs or credits associated with our pension and postretirement plans and (iii) foreign currency translation adjustments. The gains and losses on hedging items primarily relate to the derivative contracts associated with our hedging of anticipated future cash flows from the sales and purchases of natural gas, natural gas liquids and crude oil. Amounts related to our pension and postretirement plans result from gains and losses and prior service costs or credits that have not been recognized as a component of net periodic benefit costs. The translation adjustments are a cumulative total, resulting from translating all of our foreign denominated assets and liabilities at current exchange rates, while equity is translated by using historical or weighted-average exchange rates.

The total “Accumulated Other Comprehensive Loss” balance of $53.4 million included in the accompanying Consolidated Balance Sheet at December 31, 2008 consisted of (i) $5.1 million representing unrecognized net gains on energy commodity price risk management activities, (ii) $35.8 million representing unrecognized net gains relating to foreign currency translation adjustments and (iii) $94.3 million representing unrecognized net losses relating to the employee benefit plans. The total “Accumulated Other Comprehensive Loss” balance of $247.7 million included in the accompanying Consolidated Balance Sheet at December 31, 2007 consisted of (i) $237.3 million representing unrecognized net losses on energy commodity price risk management activities, (ii) $18.4 million representing unrecognized net gains relating to foreign currency translation adjustments and (iii) $28.8 million representing unrecognized net losses relating to the employee benefit plans.

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

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

For each of the years ended December 31, 2008 and 2007, our value-at-risk reached a high of $1.8 million and $2.1 million, respectively, and a low of $0.7 million and $0.7 million, respectively. Value-at-risk as of December 31, 2008 was $0.7 million, and averaged $1.5 million for 2008. Value-at-risk as of December 31, 2007 was $1.7 million, and averaged $1.4 million for 2007.

Our calculated value-at-risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio of derivative contracts assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year. In addition, as discussed above, we enter into these derivative contracts solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivative contracts, with the exception of a minor amount of hedging inefficiency, is offset by changes in the value of the underlying physical transactions. For more information on our risk management activities, see Note 15 of the accompanying Notes to Consolidated Financial Statements.

Interest Rate Risk

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

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

As of December 31, 2008 and 2007, the carrying values of our long-term fixed rate debt were approximately $9,232.8 million and $8,439.2 million, respectively. These amounts compare to fair values of $9,838.1 million and $10,651.3 million as of December 31, 2008 and 2007, respectively. A 100 basis point change of the average interest rates applicable to such debt for 2008 and 2007 would result in changes of approximately $98.4 million and $106.5 million, respectively, in the fair values of these instruments.

The carrying value of our long-term variable rate debt, excluding the value of interest rate swap agreements (discussed below), was $2,894.0 million and $6,858.2 million as of December 31, 2008 and 2007, respectively. A 100 basis point change of the weighted-average interest rate applicable to such debt, when applied to our outstanding balance of variable rate debt as of December 31, 2008 and 2007, including adjustments for notional swap amounts, would result in changes of approximately $28.9 million and $68.6 million, respectively, in our 2008 and 2007 annual pre-tax earnings.

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

As of December 31, 2008, Kinder Morgan Energy Partners was a party to an interest rate swap agreement with a notional principal amount of $2.8 billion. As of December 31, 2007, we and our subsidiary Kinder Morgan Energy Partners were party to interest rate swap agreements with notional principal amounts of $275 million and $2.3 billion, respectively, for a consolidated total of $2.575 billion. An interest rate swap agreement is a contractual agreement entered into between two counterparties under which each agrees to make periodic interest payments to the other for an agreed period of time based upon a predetermined amount of principal, which is called the notional principal amount. Normally at each payment or settlement date, the party who owes more pays the net amount; so at any given settlement date only one party actually makes a payment. The principal amount is notional because there is no need to exchange actual amounts of principal.

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

As of both December 31, 2008 and 2007, all of our interest rate swap agreements represented fixed-for-variable rate swaps, where we agreed to pay our counterparties a variable rate of interest on a notional principal amount, comprised of principal amounts from various series of our long-term fixed rate senior notes. In exchange, our counterparties agreed to pay us a fixed rate of interest, thereby allowing us to transform our fixed rate liabilities into variable rate obligations without the incurrence of additional loan origination or conversion costs. We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements.

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

See Notes 14, 15 and 23 of the accompanying Notes to Consolidated Financial Statements for additional information on activity related to our debt instruments and interest rate swap agreements.

Foreign Currency Risk

We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To mitigate this risk, we have several receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency interest rate swap agreements that have been designated as a hedge of our net investment in Canadian operations in accordance with SFAS No. 133. A 1% change in the U.S. Dollar to Canadian Dollar exchange rate would impact the fair value of these swap agreements by approximately $1.09 million.

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Item 8.    Financial Statements and Supplementary Data.

INDEX

	Page
Report of Independent Registered Public Accounting Firm	44-45
Consolidated Statements of Operations	46
Consolidated Statements of Comprehensive Income	47
Consolidated Balance Sheets	48-49
Consolidated Statements of Stockholders’ Equity	50-52
Consolidated Statements of Cash Flows	53-54
Notes to Consolidated Financial Statements	55-135
Selected Quarterly Financial Data (Unaudited)	135-136
Supplementary Information on Oil and Gas Producing Activities (Unaudited)	137-140

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Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan, Inc. (formerly known as Knight Inc.):

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Kinder Morgan, Inc. (formerly known as Knight Inc.) and its subsidiaries (the "Company") at December 31, 2008 and 2007, and the results of their operations and their cash flows for the year ended December 31, 2008 and the period from June 1, 2007 to December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting (not presented herein) appearing in item 9A of the Company's 2008 Annual Report on Form 10-K.  Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audit.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audits of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

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

·   The bulk terminal assets acquired from Chemserve, Inc., effective August 15, 2008; and

·   The refined petroleum products storage terminal acquired from ConocoPhillips, effective December 10, 2008,

(the “Acquired Businesses”) from its assessment of internal control over financial reporting as of December 31, 2008 because these businesses were each acquired by the Company in  purchase business combinations during 2008.  We have also excluded the Acquired Businesses from our audit of internal control over financial reporting.  These Acquired Businesses are wholly-owned subsidiaries whose total assets and total revenues, in the aggregate, represent 0.16% and 0.01%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2008.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

PricewaterhouseCoopers LLP

Houston, Texas

March 31, 2009, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the adoption of FASB Statement No. 160 discussed in Note 1, as to which the date is September 18, 2009.

44

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Kinder Morgan, Inc. (formerly known as Knight Inc.):

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the results of their operations and their cash flows for the period from January 1, 2007 to May 31, 2007, and the year ended December 31, 2006 of Kinder Morgan Inc. (formerly known as Knight Inc.) and its subsidiaries (the "Company") in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

PricewaterhouseCoopers LLP

Houston, Texas

March 28, 2008, except with respect to Note 19, for which the date is January 8, 2009 and to our opinion on the consolidated financial statements insofar as it relates to the effects of the adoption of FASB Statement No. 160 discussed in Note 1, as to which the date is September 18, 2009.

45

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions)

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Operating Revenues
Natural Gas Sales	$	7,705.8		$	3,623.1		$	2,430.6		$	6,225.6
Services		2,904.0			2,049.8			1,350.5			3,082.3
Product Sales and Other		1,485.0			721.8			384.0			900.7
Total Operating Revenues		12,094.8			6,394.7			4,165.1			10,208.6
Operating Costs and Expenses
Gas Purchases and Other Costs of Sales		7,744.0			3,656.6			2,490.4			6,339.4
Operations and Maintenance		1,318.0			943.3			476.1			1,155.4
General and Administrative		352.5			175.6			283.6			305.1
Depreciation, Depletion and Amortization		918.4			472.3			261.0			531.4
Taxes, Other Than Income Taxes		191.4			110.1			74.4			165.0
Other Expenses (Income)		9.3			(6.0	)		(2.3	)		(34.1	)
Impairment of Assets		4,033.3			-			377.1			1.2
Total Operating Costs and Expenses		14,566.9			5,351.9			3,960.3			8,463.4
Operating Income (Loss)		(2,472.1	)		1,042.8			204.8			1,745.2
Other Income and (Expenses)
Earnings of Equity Investees		195.4			53.4			38.3			98.6
Interest Expense, Net		(633.4	)		(581.5	)		(241.1	)		(552.8	)
Interest Income (Expense)—Deferrable Interest Debentures		5.1			(12.8	)		(9.1	)		(21.9	)
Other, Net		7.0			11.6			0.6			(8.6	)
Total Other Income and (Expenses)		(425.9	)		(529.3	)		(211.3	)		(484.7	)
Income (Loss) from Continuing Operations Before Income Taxes		(2,898.0	)		513.5			(6.5	)		1,260.5
Income Taxes		304.3			227.4			135.5			285.9
Income (Loss) from Continuing Operations		(3,202.3	)		286.1			(142.0	)		974.6
Income (Loss) from Discontinued Operations, Net of Tax		(0.9	)		(1.5	)		298.6			(528.5	)
Net Income (Loss)		(3,203.2	)		284.6			156.6			446.1
Net Income Attributable to Noncontrolling Interests		(396.1	)		(37.6	)		(90.7	)		(374.2	)
Net Income (Loss) Attributable to Kinder Morgan, Inc.’s Stockholder	$	(3,599.3	)	$	247.0		$	65.9		$	71.9

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

46

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Net Income (Loss)	$	(3,203.2	)	$	284.6		$	156.6		$	446.1
Other Comprehensive Income (Loss), Net of Tax:
Change in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax of $155.4, Tax Benefit of $141.7, $21.5, and Tax of $14.0, Respectively)		507.4			(638.6	)		(71.4	)		(100.3	)
Reclassification of Change in Fair Value of Derivatives to Net Income (Net of Tax of $104.0, Tax Benefit of $0.3, Tax of $15.5 and $40.9, Respectively)		418.2			137.2			66.8			352.5
Employee Benefit Plans:
Prior Service Cost Arising During Period (Net of Tax Benefit of $0.2 and $1.0, Respectively)		-			(1.4	)		(1.7	)		-
Net (Loss) Gain Arising During Period (Net of Tax Benefit of $37.3, $15.3, and Tax of $6.7, Respectively)		(64.6	)		(28.4	)		11.2			-
Amortization of Prior Service Cost Included in Net Periodic Benefit Costs (Net of Tax Benefit of $0.2)		-			-			(0.4	)		-
Amortization of Net Loss (Gain) Included in Net Periodic Benefit Costs (Net of Tax of $0.2, Tax Benefit of Less than $0.1, and Tax of $0.8, Respectively)		0.1			(0.2	)		1.4			-
Change in Foreign Currency Translation Adjustment (Net of Tax Benefit of $48.2, Tax of $8.4, $4.8 and Tax Benefit of $11.5, Respectively)		(218.3	)		67.9			58.9			(31.3	)
Adjustment to Recognize Minimum Pension Liability (Net of Tax of $1.7)		-			-			-			3.5
Total Other Comprehensive Income (Loss)		642.8			(463.5	)		64.8			224.4
Comprehensive Income (Loss)		(2,560.4	)		(178.9	)		221.4			670.5
Comprehensive (Income) Loss Attributable to Noncontrolling Interests		(844.6	)		175.3			(115.7	)		(560.7	)
Comprehensive Income (Loss) Attributable to Kinder Morgan, Inc.	$	(3,405.0	)	$	(3.6	)	$	105.7		$	109.8

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

47

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2008		December 31, 2007
ASSETS
Current Assets
Cash and Cash Equivalents	$	118.6	$	148.6
Restricted Deposits		-		67.9
Accounts, Notes and Interest Receivable, Net		992.5		975.2
Inventories		44.2		37.8
Gas Imbalances		14.1		26.9
Assets Held for Sale		-		3,353.3
Fair Value of Derivative Instruments		115.2		37.1
Other		32.6		36.8
		1,317.2		4,683.6
Property, Plant and Equipment, Net		16,109.8		14,803.9
Notes Receivable—Related Parties		178.1		87.9
Investments		1,827.4		1,996.2
Goodwill		4,698.7		8,174.0
Other Intangibles, Net		251.5		321.1
Assets Held for Sale, Non-current		-		5,634.6
Fair Value of Derivative Instruments, Non-current		828.0		143.5
Deferred Charges and Other Assets		234.2		256.2
Total Assets	$	25,444.9	$	36,101.0

48

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(In millions except share and per share amounts)

	December 31, 2008			December 31, 2007
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current Maturities of Long-term Debt	$	293.7		$	79.8
Notes Payable		8.8			888.1
Cash Book Overdrafts		45.2			30.7
Accounts Payable		849.8			943.7
Accrued Interest		241.9			242.7
Accrued Taxes		152.1			728.2
Gas Imbalances		12.4			23.7
Liabilities Held for Sale		-			168.2
Fair Value of Derivative Instruments		129.5			594.7
Other		281.3			240.0
		2,014.7			3,939.8
Long-term Debt
Outstanding Notes and Debentures		11,020.1			14,714.6
Deferrable Interest Debentures Issued to Subsidiary Trusts		35.7			283.1
Preferred Interest in General Partner of Kinder Morgan Energy Partners		100.0			100.0
Value of Interest Rate Swaps		971.0			199.7
		12,126.8			15,297.4
Deferred Income Taxes, Non-current		2,081.3			1,849.4
Liabilities Held for Sale, Non-current		-			2,424.1
Fair Value of Derivative Instruments, Non-current		92.2			888.0
Other Long-term Liabilities and Deferred Credits		653.0			566.8
		14,953.3			21,025.7
Commitments and Contingencies (Notes 18 and 21)
Stockholders’ Equity
Common Stock – Authorized and Outstanding – 100 Shares, Par Value $0.01 Per Share		-			-
Additional Paid-in Capital		7,810.0			7,822.2
Retained Earnings (Deficit)		(3,352.3	)		247.0
Accumulated Other Comprehensive Loss		(53.4	)		(247.7	)
Total Kinder Morgan, Inc. Stockholder’s Equity		4,404.3			7,821.5
Noncontrolling Interests		4,072.6			3,314.0
Total Stockholders’ Equity		8,476.9			11,135.5
Total Liabilities and Stockholders’ Equity	$	25,444.9		$	36,101.0

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

49

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in millions)

	Successor Company
	Year Ended December 31, 2008					Seven Months Ended December 31, 2007
	Shares		Amount			Shares		Amount
Kinder Morgan, Inc. Stockholder’s Equity
Common Stock		100	$	-			100	$	-
Additional Paid-in Capital
Beginning Balance				7,822.2					-
MBO Purchase Price				-					7,831.2
Revaluation of Kinder Morgan Energy Partners (“KMP”) Investment (Note 14)				(19.8	)				(13.4	)
A-1 Unit Amortization				7.6					4.4
Ending Balance				7,810.0					7,822.2
Retained Earnings (Deficit)
Beginning Balance				247.0					-
Net (Loss) Income				(3,599.3	)				247.0
Ending Balance				(3,352.3	)				247.0
Accumulated Other Comprehensive  Loss (Net of Tax)
Derivatives
Beginning Balance				(246.7	)				2.9
Change in Fair Value of Derivatives Utilized for Hedging Purposes				212.0					(249.6	)
Reclassification of Change in Fair Value of Derivatives to Net Income				117.1					-
Ending Balance				82.4					(246.7	)
Foreign Currency Translation
Beginning Balance				27.6					-
Currency Translation Adjustment				(68.7	)				27.6
Ending Balance				(41.1	)				27.6
Employee Benefit Plans
Beginning Balance				(28.6	)				-
Benefit Plan Adjustments				(66.5	)				(28.4	)
Benefit Plan Amortization				0.4					(0.2	)
Ending Balance				(94.7	)				(28.6	)
Total Accumulated Other Comprehensive Loss				(53.4	)				(247.7	)
Total Kinder Morgan, Inc. Stockholder’s Equity		100		4,404.3			100		7,821.5
Noncontrolling Interests
Beginning Balance				3,314.0					3,343.9
Impact from Equity Transactions of Kinder Morgan Energy Partners				(21.4	)				(12.9	)
Gain on Sale of Discontinued Operations				-					(56.1	)
Distributions to Noncontrolling Interests				(630.7	)				(260.5	)
Contributions from Noncontrolling Interests				561.5					343.5
Kinder Morgan Energy Partners’ TransMountain Pipeline Acquisition				-					(4.7	)
Net Income Included in Discontinued Operations				-					141.6
Other				4.6					(5.5	)
Comprehensive Income (Loss)
Net Income				396.1					37.6
Other Comprehensive Income (Loss), Net of Tax
Change in Fair Value of Derivatives Utilized for Hedging Purposes				295.4					(389.0	)
Reclassification of Change in Fair Value of Derivatives to Net Income				301.1					137.2
Change in Foreign Currency Translation Adjustment				(149.6	)				40.3
Change in Employee Benefit Plans				1.6					(1.4	)
Total Other Comprehensive Income (Loss)				448.5					(212.9	)
Total Comprehensive Income (Loss)				844.6					(175.3	)
Ending Balance				4,072.6					3,314.0
Total Stockholders’ Equity		100	$	8,476.9			100	$	11,135.5

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

50

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

(Dollars in millions)

	Predecessor Company
	Five Months Ended May 31, 2007						Year Ended December 31, 2006
	Shares			Amount			Shares			Amount
Kinder Morgan, Inc. Stockholder’s Equity
Common Stock
Beginning Balance		149,166,709		$	745.8			148,479,863		$	742.4
Employee Benefit Plans		149,894			0.8			686,846			3.4
Ending Balance		149,316,603			746.6			149,166,709			745.8
Additional Paid-in Capital
Beginning Balance					3,048.9						3,056.3
Revaluation of Kinder Morgan Energy Partners (“KMP”) Investment (Note 14)					3.4						(40.3	)
Employee Benefit Plans					7.7						33.2
Tax Benefits from Employee Benefit Plans					56.7						18.6
Implementation of SFAS No. 123(R) Deferred Compensation Balance					-						(36.9	)
Deferred Compensation (Note 17)					21.9						18.0
Ending Balance					3,138.6						3,048.9
Retained Earnings
Beginning Balance					778.7						1,175.3
Net Income					65.9						71.9
Cash Dividends, Common Stock					(234.9	)					(468.5	)
Implementation of FIN No. 48 (Note 13)					(4.8	)					-
Ending Balance					604.9						778.7
Treasury Stock at Cost
Beginning Balance		(15,022,751	)		(915.9	)		(14,712,901	)		(885.7	)
Treasury Stock Acquired		-			-			(339,800	)		(31.5	)
Employee Benefit Plans		(7,384	)		(0.5	)		29,950			1.3
Ending Balance		(15,030,135	)		(916.4	)		(15,022,751	)		(915.9	)
Deferred Compensation Plans
Beginning Balance					-						(36.9	)
Implementation of SFAS No. 123(R) Balance Transfer to Additional Paid-in Capital					-						36.9
Ending Balance					-						-
Accumulated Other Comprehensive Loss (Net of Tax)
Derivatives
Beginning Balance					(60.8	)					(127.1	)
Change in Fair Value of Derivatives Utilized for Hedging Purposes					(21.3	)					44.6
Reclassification of Change in Fair Value of Derivatives to Net Income					10.3						21.7
Ending Balance					(71.8	)					(60.8	)
Foreign Currency Translation
Beginning Balance					(24.5	)					7.4
Currency Translation Adjustment					40.1						(31.9	)
Ending Balance					15.6						(24.5	)
Minimum Pension Liability
Beginning Balance					-						(7.3	)
Minimum Pension Liability Adjustments					-						7.3
Ending Balance					-						-
Employee Retirement Benefits
Beginning Balance					(50.6	)					-
Benefit Plan Adjustments					-						(50.6	)
Benefit Plan Amortization					10.7						-
Ending Balance					(39.9	)					(50.6	)
Total Accumulated Other Comprehensive Loss					(96.1	)					(135.9	)
Total Kinder Morgan, Inc. Stockholder’s Equity		134,286,468		$	3,477.6			134,143,958		$	3,521.6

51

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

(Dollars in millions)

	Predecessor Company
	Five Months Ended May 31, 2007					Year Ended December 31, 2006
	Shares		Amount			Shares		Amount
Noncontrolling Interests
Beginning Balance			$	3,095.4				$	1,247.3
Adjustment to Initially Apply EITF No. 04-5				-					1,453.1
Impact from Equity Transactions of Kinder Morgan Energy Partners				(22.7	)				44.3
Issuance of Shares by Kinder Morgan Management, LLC				317.0					12.4
Distributions to Noncontrolling Interests				(248.9	)				(575.2	)
Contributions from Noncontrolling Interests				15.0					355.4
Kinder Morgan Energy Partners’ TransMountain Pipeline Acquisition				72.1					-
Other				0.3					(0.1	)
Comprehensive Income (Loss)
Net Income				90.7					374.2
Other Comprehensive Income (Loss), Net of Tax
Change in Fair Value of Derivatives Utilized for Hedging Purposes				(50.1	)				(144.9	)
Reclassification of Change in Fair Value of Derivatives to Net Income				56.5					330.8
Change in Foreign Currency Translation Adjustment				18.8					0.6
Change in Employee Benefit Plans				(0.2	)				(2.5	)
Total Other Comprehensive Income				25.0					184.0
Total Comprehensive Income				115.7					558.2
Ending Balance				3,343.9					3,095.4
Total Stockholders’ Equity		134,286,468	$	6,821.5			134,143,958	$	6,617.0

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

52

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Cash Flows from Operating Activities
Net (Loss) Income	$	(3,203.2	)	$	284.6		$	156.6		$	446.1
Adjustments to Reconcile Net (Loss) Income to Net Cash Flows from Operating Activities
Loss (Income) from Discontinued Operations, Net of Tax		0.9			11.9			(287.9	)		542.8
Loss from Impairment of Assets		4,033.3			-			377.1			1.2
Loss on Early Extinguishment of Debt		23.6			-			4.4			-
Depreciation, Depletion and Amortization		918.4			476.2			264.9			540.3
Deferred Income Taxes		(496.4	)		(89.8	)		138.7			10.8
Income from the Allowance for Equity Funds Used During Construction		(10.9	)		-			-			-
Equity in Earnings of Equity Investees		(195.4	)		(54.3	)		(39.1	)		(100.6	)
Distributions from Equity Investees		241.6			86.5			48.2			74.8
Gains from Property Casualty Indemnifications		-			-			(1.8	)		(15.2	)
Net Losses (Gains) on Sales of Assets		9.2			(6.3	)		(2.6	)		(22.0	)
Mark-to-Market Interest Rate Swap (Gain) Loss		(19.8	)		-			-			22.3
Foreign Currency Loss		0.2			-			15.5			-
Changes in Gas in Underground Storage		(28.0	)		51.3			(84.2	)		(35.3	)
Changes in Working Capital Items (Note 6)		(44.9	)		104.0			(202.9	)		80.0
Proceeds from (Payment for) Termination of Interest Rate Swaps		192.0			(2.2	)		51.9			-
Kinder Morgan Energy Partners’ Rate Reparations, Refunds and Reserve Adjustments		(13.7	)		140.0			-			(19.1	)
Other, Net		(9.3	)		45.8			54.4			(31.4	)
Net Cash Flows Provided by Continuing Operations		1,397.6			1,047.7			493.2			1,494.7
Net Cash Flows (Used in) Provided by Discontinued Operations		(0.8	)		(3.2	)		109.8			212.6
Net Cash Flows Provided by Operating Activities		1,396.8			1,044.5			603.0			1,707.3
Cash Flows from Investing Activities
Purchase of Predecessor Stock		-			(11,534.3	)		-			-
Capital Expenditures		(2,545.3	)		(1,287.0	)		(652.8	)		(1,375.6	)
Proceeds from Sale of 80% Interest in NGPL PipeCo LLC, Net of $1.1 Cash Sold		2,899.3			-			-			-
Terasen Acquisition		-			-			-			(10.6	)
Other Acquisitions		(47.6	)		(122.0	)		(42.1	)		(396.5	)
Loans to Customers		(109.6	)		-			-			-
Proceeds from (Investments in) NGPL PipeCo LLC Restricted Cash		3,106.4			(3,030.0	)		-			-
Net Proceeds from (Investment in) Margin Deposits		71.0			(39.3	)		(54.8	)		38.6
Distributions from Equity Investees		98.1			-			-			-
Contributions to Investments		(366.2	)		(246.4	)		(29.7	)		(6.1	)
Change in Natural Gas Storage and Natural Gas Liquids Line Fill Inventory		(7.2	)		10.0			8.4			(12.9	)
Property Casualty Indemnifications		-			-			8.0			13.1
Net Proceeds (Costs of Removal) from Sales of Assets		111.1			301.3			(1.5	)		92.2
Net Cash Flows Provided by (Used in) Continuing Investing Activities		3,210.0			(15,947.7	)		(764.5	)		(1,657.8	)
Net Cash Flows Provided by (Used in) Discontinued Investing Activities		-			196.6			1,488.2			(138.1	)
Net Cash Flows Provided by (Used in) Investing Activities	$	3,210.0		$	(15,751.1	)	$	723.7		$	(1,795.9	)

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KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(In millions)

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Cash Flows from Financing Activities
Short-term Debt, Net	$	(879.3	)	$	(52.6	)	$	(247.5	)	$	1,009.5
Long-term Debt Issued		2,113.2			8,805.0			1,000.0			-
Long-term Debt Retired		(5,874.6	)		(829.2	)		(302.4	)		(140.7	)
Issuance of Kinder Morgan, G.P., Inc. Preferred Stock		-			100.0			-			-
Discount (Premium) on Early Extinguishment of Debt		69.2			-			(4.2	)		-
Cash Book Overdraft		14.5			(14.0	)		(14.9	)		17.9
Issuance of Shares by Kinder Morgan Management, LLC		-			-			297.9			-
Other Common Stock Issued		-			-			9.9			38.7
Excess Tax Benefits from Share-based Payments		-			-			56.7			18.6
Cash Paid to Share-based Award Holders Due to Going Private Transaction		-			(181.1	)		-			-
Contributions from Successor Investors		-			5,112.0			-			-
Short-term Advances from (to) Unconsolidated Affiliates		2.7			10.9			2.3			(4.9	)
Treasury Stock Acquired		-			-			-			(34.3	)
Cash Dividends, Common Stock		-			-			(234.9	)		(468.5	)
Distributions to Noncontrolling Interests		(630.3	)		(259.6	)		(248.9	)		(575.0	)
Contributions from Noncontrolling Interests		561.5			342.9			-			353.8
Debt Issuance Costs		(15.9	)		(81.5	)		(13.1	)		(4.8	)
Other, Net		10.9			4.0			(0.1	)		(3.5	)
Net Cash Flows (Used In) Provided by Continuing Financing Activities		(4,628.1	)		12,956.8			300.8			206.8
Net Cash Flows Provided by (Used in) Discontinued Financing Activities		-			-			140.1			(118.1	)
Net Cash Flows (Used In) Provided by Financing Activities		(4,628.1	)		12,956.8			440.9			88.7
Effect of Exchange Rate Changes on Cash		(8.7	)		(2.8	)		7.6			6.6
Effect of Accounting Change on Cash		-			-			-			12.1
Cash Balance Included in Assets Held for Sale		-			(1.1	)		(2.7	)		(5.6	)
Net (Decrease) Increase in Cash and Cash Equivalents		(30.0	)		(1,753.7	)		1,772.5			13.2
Cash and Cash Equivalents at Beginning of Period		148.6			1,902.3			129.8			116.6
Cash and Cash Equivalents at End of Period	$	118.6		$	148.6		$	1,902.3		$	129.8

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Nature of Operations and Summary of Significant Accounting Policies

Nature of Operations

We are a large energy transportation and storage company, operating or owning an interest in approximately 36,000 miles of pipelines and approximately 170 terminals. We have both regulated and nonregulated operations. We also own the general partner interest and a significant limited partner interest in Kinder Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership. Our executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas 77002 and our telephone number is (713) 369-9000. Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries both before and after the Going Private transaction discussed below. Unless the context requires otherwise, references to “Kinder Morgan Energy Partners” and “KMP” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.

Kinder Morgan Management, LLC, referred to in this report as “Kinder Morgan Management” is a publicly traded Delaware limited liability company that was formed on February 14, 2001. Kinder Morgan G.P., Inc., of which we indirectly own all of the outstanding common equity, owns all of Kinder Morgan Management’s voting shares. Kinder Morgan Management’s shares (other than the voting shares we hold) are traded on the New York Stock Exchange under the ticker symbol “KMR.” Kinder Morgan Management, pursuant to a delegation of control agreement, has been delegated, to the fullest extent permitted under Delaware law, all of Kinder Morgan G.P., Inc.’s power and authority to manage and control the business and affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.’s right to approve certain transactions.

Basis of Presentation

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

Our consolidated financial statements include the accounts of Kinder Morgan, Inc. and our majority-owned subsidiaries, as well as those of (i) Kinder Morgan Energy Partners, (ii) Kinder Morgan Management and (iii) Triton Power Company LLC, in which we have a preferred investment. Except for Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC, investments in 50% or less owned operations are accounted for under the equity method. All material intercompany transactions and balances have been eliminated. Certain prior period amounts have been reclassified to conform to the current presentation. Notwithstanding the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our financial statements, we are not liable for, and our assets are not available to satisfy, the obligations of Kinder Morgan Energy Partners and/or its subsidiaries and vice versa. Responsibility for payments of obligations reflected in our or Kinder Morgan Energy Partners’ financial statements is a legal determination based on the entity that incurs the liability.

On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of Kinder Morgan Holdco LLC (formerly Knight Holdco LLC) , with Kinder Morgan, Inc. continuing as the surviving legal entity and subsequently renamed Knight Inc. until July 15, 2009 when the Company’s name reverted to Kinder Morgan, Inc. Kinder Morgan Holdco LLC  is a private company owned by Richard D. Kinder, our Chairman and Chief Executive Officer; our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez Sarofim and Michael C. Morgan; other members of our senior management, most of whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan Management; and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This transaction is referred to in this report as the Going Private transaction. As a result of this transaction, we are now privately owned, our stock is no longer traded on the New York Stock Exchange, and we have adopted a new basis of accounting for our assets and liabilities. This transaction was a “business combination” for accounting purposes, requiring that these investors, pursuant to SFAS No. 141, Business Combinations, record the assets acquired and liabilities assumed at their fair market values as of the acquisition date, resulting in a new basis of accounting.

As a result of the application of the SEC rules and guidance regarding “push down” accounting, the investors’ new accounting basis in our assets and liabilities is reflected in our financial statements effective with the closing of the Going Private transaction. Therefore, in the accompanying Consolidated Financial Statements, transactions and balances prior to the closing of the Going Private transaction (the amounts labeled “Predecessor Company”) reflect the historical accounting basis in our assets and liabilities, while the amounts subsequent to the closing (labeled “Successor Company”) reflect the push down of the investors’ new accounting basis to our financial statements. Hence, there is a blackline division on the financial statements and relevant notes, which is intended to signify that the amounts shown for periods prior to and subsequent to the Going Private transaction are not comparable.

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As required by SFAS No. 141 (applied by the investors and pushed down to our financial statements), effective with the closing of the Going Private transaction, all of our assets and liabilities have been recorded at their estimated fair market values based on an allocation of the aggregate purchase price paid in the Going Private transaction. To the extent that we consolidate less than wholly owned subsidiaries (such as Kinder Morgan Energy Partners, Kinder Morgan Management and Triton Power Company LLC), the reported assets and liabilities for these entities have been given a new accounting basis only to the extent of our economic ownership interest in those entities. Therefore, the assets and liabilities of these entities are included in our financial statements, in part, at a new accounting basis reflecting the investors’ purchase of our economic interest in these entities (approximately 50% in the case of Kinder Morgan Energy Partners and 14% in the case of Kinder Morgan Management). The remaining percentage of these assets and liabilities, reflecting the continuing noncontrolling ownership interest, is included at its historical accounting basis. The purchase price paid in the Going Private transaction and the allocation of that purchase price is as follows:

	(In millions)
The Total Purchase Price Consisted of the Following
Cash Paid	$	5,112.0
Kinder Morgan, Inc. Shares Contributed		2,719.2
Equity Contributed		7,831.2
Cash from Issuances of Long-term Debt		4,696.2
Total Purchase Price	$	12,527.4
The Allocation of the Purchase Price is as Follows
Current Assets	$	1,551.2
Investments		897.8
Goodwill		13,786.1
Property, Plant and Equipment, Net		15,281.6
Deferred Charges and Other Assets		1,639.8
Current Liabilities		(3,279.5	)
Deferred Income Taxes, Non-current		(2,392.8	)
Other Long-term Liabilities and Deferred Credits		(1,786.3	)
Long-term Debt		(9,855.9	)
Noncontrolling Interests in Equity of Subsidiaries		(3,314.6	)
	$	12,527.4

The following is a reconciliation of shares purchased and contributed and the Going Private transaction purchase price (in millions except per share information):

	Number of Shares		Price per Share		Total Value
Shares Purchased with Cash		107.6	$	107.50	$	11,561.3
Shares Contributed
Richard D. Kinder		24.0	$	101.00		2,424.0
Other Kinder Morgan, Inc. Management and Board Members		2.7	$	107.50		295.2
Total Shares Contributed		26.7				2,719.2
Total Shares Outstanding as of May 31, 2007		134.3				14,280.5
Less: Portion of Shares Acquired using Kinder Morgan, Inc. Cash on Hand						(1,756.8	)
Add: Cash Contributions by Management At or After May 30, 2007						3.7
Purchase Price					$	12,527.4

The shares contributed by members of management and the board members other than Richard D. Kinder who were investors in the Going Private transaction were valued at $107.50 per share, the same as the amount per share paid to the public shareholders in the Going Private transaction. Richard D. Kinder agreed to value the shares he contributed at $101.00 per share because Mr. Kinder agreed to participate in the transaction at less than the merger price in order to help increase the merger price for the other public shareholders.

Revenue Recognition Policies

We recognize revenues as services are rendered or goods are delivered and, if applicable, title has passed. We generally sell natural gas under long-term agreements, with periodic price adjustments. In some cases, we sell natural gas under short-term

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agreements at prevailing market prices. In all cases, we recognize natural gas sales revenues when the natural gas is sold at a fixed or determinable price, delivery has occurred and title has transferred, and collectibility of the revenue is reasonably assured. The natural gas we market is primarily purchased gas produced by third parties, and we market this gas to power generators, local distribution companies, industrial end-users and national marketing companies. We recognize gas gathering and marketing revenues in the month of delivery based on customer nominations and, in general our natural gas marketing revenues are recorded at gross, rather than net of cost of gas sold.

We provide various types of natural gas storage and transportation services to customers. When we provide these services, the natural gas remains the property of these customers at all times. In many cases (generally described as “firm service”), the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as “interruptible service”), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to our “firm” and “interruptible” transportation services, we also provide natural gas park and loan service to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized based on the terms negotiated under these contracts.

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

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

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

Restricted Deposits

Except as discussed following, Restricted Deposits consist of restricted funds on deposit with brokers in support of our risk management activities (see Note 15). The $3 billion of proceeds from NGPL PipeCo LLC’s sale of debt in a private placement (see Note 10) were held in escrow and are included in the caption “Current Assets: Assets Held for Sale” in the accompanying Consolidated Balance Sheet at December 31, 2007.

Accounts Receivable

The caption “Accounts, Notes and Interest Receivable, Net” in the accompanying Consolidated Balance Sheets is presented net of allowances for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved.

Inventory

Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market.

Gas Imbalances and Gas Purchase Contracts

We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting

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pipelines and shippers under various operational balancing and shipper imbalance agreements. Natural gas imbalances are settled in cash or made up in-kind subject to the terms of the various pipelines’ tariffs or other contractual provisions.

Assets and Liabilities Held for Sale

On December 10, 2007, we entered into a definitive agreement to sell an 80% ownership interest in our NGPL business segment (primarily MidCon Corp, which was the parent of Natural Gas Pipeline Company of America) to Myria Acquisition Inc. (“Myria”), a Delaware corporation, for approximately $5.9 billion, subject to certain adjustments. The closing of the sale occurred on February 15, 2008. We continue to operate NGPL assets pursuant to a 15-year operating agreement. See Note 10 for further information regarding this transaction.

In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as of December 31, 2007, 100% of the assets and liabilities in our NGPL business segment were reclassified to assets and liabilities held for sale in connection with our February 2008 sale of an 80% interest in that segment. The non-current assets and long-term debt held for sale balances were reduced by the 20% ownership interest, which we retained in the NGPL business segment and recorded as an investment. Therefore, the accompanying Consolidated Balance Sheet at December 31, 2007 includes the following:

	December 31, 2007
Current Assets: Assets Held for Sale
Restricted Deposits	$	3,030.0
Other		323.3
	$	3,353.3
Assets Held for Sale, Non-current
Goodwill	$	5,216.4
Plant, Property and Equipment, Net		1,699.3
Deferred Charges and Other Assets		38.9
Less: Investment in Net Assets of NGPL		(1,320.0	)
	$	5,634.6
Current Liabilities: Liabilities Held for Sale	$	168.2
Liabilities Held for Sale, Non-current
Long-term Debt: Outstanding Notes and Debentures	$	3,000.0
Other Long-term Liabilities and Deferred Credits		22.4
Less: Investment in Long-term Debt of NGPL		(600.0	)
	$	2,422.4
Noncontrolling Interests	$	1.7

The 20% ownership interest that we retained in the NGPL business segment is included in our Consolidated Balance Sheet as of December 31, 2007 as follows:

Investments
20% Investment of NGPL’s Net Assets	$	1,320.0
20% Investment of NGPL’s Long-term Debt		(600.0	)
	$	720.0

Pensions and Other Postretirement Benefits

We account for pension and other postretirement benefit plans according to the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R). This Statement requires us to fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and postretirement benefit plans as either assets or liabilities on our balance sheet.  For more information on our pension and postretirement benefit disclosures, see Note 16.

Accounting for Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids and crude oil. We also utilize interest rate swap agreements to mitigate our

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risk from fluctuations in interest rates and cross-currency interest rate swap agreements to mitigate foreign currency risk from our investments in businesses owned and operated outside the United States. Pursuant to current accounting provisions, we record our derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities; see Note 15.

Property, Plant and Equipment

We report property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. For our pipeline system assets, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales. Gains and losses on minor system sales, excluding land, are recorded to the appropriate accumulated depreciation reserve. Gains and losses for operating systems sales and land sales are booked to income or expense accounts in accordance with regulatory accounting guidelines.

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

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

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

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

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

We evaluate the impairment of our long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 requires that long-lived assets that are to be disposed of by sale be measured at

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the lower of book value or fair value less the cost to sell. We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition are less than its carrying amount.

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

Goodwill

Goodwill represents the excess of cost over fair value of the net assets of businesses acquired. The Company tests for impairment of goodwill on an annual basis and at any other time if events occur or circumstances indicate that the carrying amount of goodwill may not be recoverable. See Note 3 for more information about Goodwill and our annual impairment test.

Equity Method of Accounting

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

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. Note 13 contains information about our income taxes, including the components of our income tax provision and the composition of our deferred income tax assets and liabilities.

In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments including our Kinder Morgan Energy Partners investment. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investment in Kinder Morgan Energy Partners. See Note 3 regarding the Going Private transaction goodwill assigned to our Kinder Morgan Energy Partners investment.

Environmental Matters

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

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental matters, see Note 21.

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Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on our legal disclosures, see Note 21.

Foreign Currency Translation

We translate the financial statements of our foreign consolidated subsidiaries into United States dollars using the current rate method of foreign currency translation. Under this method, assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, revenue and expense items are translated at average rates of exchange for the period, stockholder’s equity accounts at historical exchange rates and the exchange gains and losses arising on the translation of the financial statements are reflected as a separate component of the “Accumulated Other Comprehensive Income” caption in the accompanying Consolidated Balance Sheets.

Foreign currency transaction gains or losses, other than hedges of net investments in foreign companies, are included in results of operations. In 2006, we recorded net pre-tax losses of $22.5 million from foreign currency transactions and swaps. See Note 15 for information regarding our hedges of net investments in foreign companies.

Canadian dollars are designated as C$ in these Notes to Consolidated Financial Statements. To convert December 31, 2008 balances denominated in Canadian dollars to U.S. dollars, we used the December 31, 2008 Bank of Canada closing exchange rate of 0.8210 U.S. dollars per Canadian dollar.

Transfer of Net Assets Between Entities Under Common Control

We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the income statement of the combined entity.

Accounting for Noncontrolling Interests

In January 2009, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statement. SFAS No. 160 establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries (previously referred to as minority interests) and is applied prospectively with the exception of the presentation and disclosure requirements, which must be applied retrospectively for all periods presented.

Noncontrolling ownership interests in consolidated subsidiaries are now presented in the accompanying Consolidated Balance Sheets within equity as a separate component from our stockholder’s equity. Net Income in the accompanying Consolidated Statements of Operations and Comprehensive Incomenow includes earnings attributable to both Kinder Morgan, Inc.’s equity, and the noncontrolling interests. In addition, changes to noncontrolling interests are identified in the accompanying Consolidated Statements of Stockholders’ Equity, and within the accompanying Consolidated Statements of Cash Flows, cash flows attributable to contributions from and distributions to noncontrolling interests have been identified.

2.   Investment in Kinder Morgan Energy Partners, L.P.

At December 31, 2008, we owned, directly, and indirectly in the form of i-units corresponding to the number of shares of Kinder Morgan Management we owned, approximately 32.8 million limited partner units of Kinder Morgan Energy Partners. These units, which consist of 16.4 million common units, 5.3 million Class B units and 11.1 million i-units, represent approximately 12.3% of the total limited partner interests of Kinder Morgan Energy Partners. See Note 9 for additional information regarding Kinder Morgan Management and Kinder Morgan Energy Partners’ i-units. In addition, we are the sole common stockholder of the general partner of Kinder Morgan Energy Partners, which holds an effective 2% combined interest in Kinder Morgan Energy Partners and its operating partnerships. Together, our limited partner and general partner interests represented approximately 14.1% of Kinder Morgan Energy Partners’ total equity interests at December 31, 2008. As of the close of the Going Private transaction, our limited partner interests and our general partner interest represented an approximate 50% economic interest in Kinder Morgan Energy Partners. This difference results from the existence of incentive distribution rights held by the general partner shareholder.

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In conjunction with Kinder Morgan Energy Partners’ acquisition of certain natural gas pipelines from us, we agreed to indemnify Kinder Morgan Energy Partners with respect to approximately $733.5 million of its debt. We would be obligated to perform under this indemnity only if Kinder Morgan Energy Partners’ assets were unable to satisfy its obligations.

Additional information regarding Kinder Morgan Energy Partners’ results of operations and financial position are contained in its Annual Report on Form 10-K for the year ended December 31, 2008.

3.  Goodwill and Other Intangibles

Goodwill

Changes in the carrying amount of our goodwill for the year ended December 31, 2008 are summarized as follows:

	December 31, 2007		Acquisitions and Purchase Price Adjustments1				Impairment of Assets			Other2			December 31, 2008
	(In millions)
Products Pipelines–KMP	$	2,179.4		$	(54.8	)	$	(1,266.5	)	$	(8.1	)	$	850.0
Natural Gas Pipelines–KMP		3,201.0			251.2			(2,090.2	)		(12.8	)		1,349.2
CO2–KMP		1,077.6			450.9			-			(6.8	)		1,521.7
Terminals–KMP		1,465.9			(9.5	)		(676.6	)		(5.6	)		774.2
Kinder Morgan Canada–KMP		250.1			-			-			(46.5	)		203.6
Consolidated Total	$	8,174.0		$	637.8		$	(4,033.3	)	$	(79.8	)	$	4,698.7

_______________

1 Adjustments relate primarily to a reallocation between goodwill and property, plant, and equipment in our final purchase price allocation.

2 Adjustments include (i) the translation of goodwill denominated in foreign currencies and (ii) reductions in goodwill due to reductions in our ownership percentage of Kinder Morgan Energy Partners.

We evaluate goodwill for impairment in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. For this purpose, we have six reporting units as follows: (i) Products Pipelines–KMP (excluding associated terminals), (ii) Products Pipelines Terminals–KMP (evaluated separately from Products Pipelines for goodwill purposes), (iii) Natural Gas Pipelines–KMP, (iv) CO–KMP, (v) Terminals–KMP and (vi) Kinder Morgan Canada–KMP. For investments we account for under the equity method of accounting, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and is not subject to amortization but rather to impairment testing in accordance with APB No. 18, The Equity Method of Accounting for Investments in Common Stock. As of both December 31, 2008 and December 31, 2007, we have reported $138.2 million of equity method goodwill within the caption “Investments” in the accompanying Consolidated Balance Sheets.

In the second quarter of 2008, we finalized the purchase price allocation associated with our May 2007 Going Private transaction, establishing the fair values of our individual assets and liabilities including assigning the associated goodwill to our six reporting units, in each case as of the May 31, 2007 acquisition date. A significant portion of the goodwill that arose in conjunction with this acquisition was determined to be associated with the general partner and significant limited partner interests in Kinder Morgan Energy Partners (a publicly traded master limited partnership, or “MLP”), attributable, in part, to the difference between the market multiples that might be paid to acquire the general partner and limited interests in an MLP and the market multiples that might be paid to acquire the individual assets that comprise that MLP. This market premium is partially attributable to the incentive distribution right that is embedded in the Kinder Morgan Energy Partners general partner interest for which a separate intangible asset was not recognized in purchase accounting because this right cannot be detached or transferred apart from the entire general partner interest.

In conjunction with our first annual impairment test of the carrying value of this goodwill, performed as of May 31, 2008, we determined that the fair value of certain reporting units that are part of our investment in Kinder Morgan Energy Partners were less than the carrying values. The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and nine times cash flows) discounted at a rate of 9.00%. In accordance with paragraph 23 of SFAS No. 142, the value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represents the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. Thus, any value generated from the inclusion of these assets in an MLP structure was not captured in the valuation of these reporting units. This resulted in several of the reporting units having fair values less than their carrying values as the incremental value created by the inclusion of these assets in an MLP structure was taken into account in the Going Private transaction and thus was used in allocating the purchase price under SFAS No. 141. To capture this value at the reporting unit level, we believe it would be necessary to recreate the MLP structure at the reporting unit level. We believe this is not feasible for Kinder Morgan, Inc. or for any market participant, as further discussed below.

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Recreating such structure would involve separating each of our reporting units into separate entities so that each reporting unit could be valued on a stand alone basis assuming each such unit was sold as an MLP. Creating separate MLPs would involve significant structural difficulties including potentially numerous adverse state and federal tax consequences to Kinder Morgan Energy Partners and its unitholders. In addition, it would involve a significant amount of tax, legal and commercial analysis, and based on that analysis may also require customer and/or joint venture consents, lender consents, and regulatory approvals and/or unitholder approval. As a result of these factors, we believe that it is not feasible to apply the MLP structure related value to the individual reporting unit level.

For the reporting units where the fair value was determined to be less than the carrying value, we determined the implied fair value of goodwill. The implied fair value of goodwill within each reporting unit was then compared to the carrying value of goodwill of each such unit, resulting in the following goodwill impairment charges by reporting units: Products Pipelines–KMP (excluding associated terminals) – $1.20 billion, Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment purposes) - $70 million, Natural Gas Pipelines–KMP – $2.09 billion, and Terminals–KMP – $677 million, for a total impairment of $4.03 billion. The goodwill impairment charges are non-cash charges and do not have any impact on our cash flows.

The decline in the market price of crude oil since May 31, 2008 has required us to update our goodwill impairment analysis of the CO2–KMP segment as of December 31, 2008. The fair value of the CO2–KMP segment was determined from the present value of the expected future cash flows based on forward prices of crude oil as of December 31, 2008. The assumed price of oil for each year in our analysis was $54.32, $63.83, $68.79, $71.07 and $72.67 for the fiscal years 2009-2013. A terminal value calculated using a market multiple for similar assets was applied to 2013 cash flows. This calculated fair value of the CO2–KMP reporting unit was greater than the book value of this reporting unit and thus at December 31, 2008 goodwill impairment was not necessary.

On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. This transaction caused us to evaluate the fair value of the Trans Mountain pipeline system in determining whether goodwill related to these assets was impaired. Accordingly, based on our consideration of supporting information obtained regarding the fair values of the Trans Mountain pipeline system assets, a goodwill impairment charge of $377.1 million was recorded in 2007.

In February 2007, we entered into a definitive agreement, which closed on May 17, 2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company with investments in regulated distribution utilities. Execution of this sale agreement constituted an event of the type that, under GAAP, required us to consider the market value indicated by the definitive sales agreement in our 2006 goodwill impairment evaluation. Accordingly, based on the fair values of these reporting unit(s) derived principally from this definitive sales agreement, an estimated goodwill impairment charge of approximately $650.5 million was recorded in the 2006 period and is reported in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006 within the caption, “Income (Loss) from Discontinued Operations, Net of Tax.”

Other Intangibles, Net

Our intangible assets other than goodwill include customer relationships, contracts and agreements, technology-based assets, lease values and other long-term assets. These intangible assets are being amortized on a straight-line basis over their estimated useful lives and are reported separately as “Other Intangibles, Net” in the accompanying Consolidated Balance Sheets. Following is information related to our intangible assets:

	December 31,
	2008			2007
	(In millions)
Customer Relationships, Contracts and Agreements
Gross Carrying Amount	$	270.9		$	321.3
Accumulated Amortization		(30.3	)		(11.6	)
Net Carrying Amount		240.6			309.7
Technology-based Assets, Lease Value and Other
Gross Carrying Amount		11.7			11.7
Accumulated Amortization		(0.8	)		(0.3	)
Net Carrying Amount		10.9			11.4
Total Other Intangibles, Net	$	251.5		$	321.1

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Amortization expense on our intangibles consisted of the following:

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Customer Relationships, Contracts and Agreements	$	18.7	$	11.6	$	6.1	$	15.0
Technology-based Assets, Lease Value and Other		0.5		0.3		0.2		0.2
Total Amortizations	$	19.2	$	11.9	$	6.3	$	15.2

As of December 31, 2008, the weighted-average amortization period for our intangible assets was approximately 16.6 years. Our estimated amortization expense for these assets for each of the next five fiscal years is approximately $17.2 million, $17.0 million, $16.8 million, $16.5 million and $16.5 million, respectively.

4.  Other Investments

Our long-term investments as of December 31, 2008 consisted of equity investments totaling $1,814.2 million and bond investments totaling $13.2 million.

Our significant equity investments as of December 31, 2008 (and our percentage of ownership interests) consisted of:

· NGPL PipeCo LLC (20%);

· West2East Pipeline LLC (51%);

· Plantation Pipe Line Company (51%);

· Red Cedar Gathering Company (49%);

· Express Pipeline System (33⅓%);

· Cortez Pipeline Company (50%);

· Fayetteville Express Pipeline LLC (50%); and

· Midcontinent Express Pipeline LLC (50%);

On February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC (formerly MidCon Corp.), which owns Natural Gas Pipeline of America and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc. (“Myria”). Pursuant to the purchase agreement, Myria acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We will continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group. See Note 10 for further discussion regarding this transaction.

Kinder Morgan Energy Partners operates and owns 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, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50%, at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economic interest in the project. According to the provisions of current accounting standards, because Kinder Morgan Energy Partners will receive 50% of the economics of the Rockies Express Pipeline project on an ongoing basis, Kinder Morgan Energy Partners is not considered the primary beneficiary of West2East Pipeline LLC and thus, accounts for its investment under the equity method of accounting.

Similarly, Kinder Morgan Energy Partners operates and owns an approximate 51% ownership interest in Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49% interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, Kinder Morgan Energy Partners does not control Plantation Pipe Line Company and accounts for its investment under the equity method of accounting.

Kinder Morgan Energy Partners acquired its ownership interest in the Red Cedar Gathering Company from us on December 31, 1999, and acquired its ownership interest in the Express pipeline system from us effective August 28, 2008. Kinder Morgan Energy Partners acquired a 50% ownership interest in Cortez Pipeline Company from affiliates of Shell in April 2000. Kinder Morgan Energy Partners formed Midcontinent Express Pipeline LLC in May 2006.

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

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growing markets. Fayetteville Express Pipeline LLC will construct the 187-mile, 42-inch diameter pipeline, which will originate in Conway County, Arkansas, continue eastward through White County, Arkansas, and terminate at an interconnect with Trunkline Gas Company’s pipeline in Quitman County, Mississippi. Pending necessary regulatory approvals, the approximately $1.2 billion pipeline project is expected to be in service by late 2010 or early 2011.

In 2007, Kinder Morgan Energy Partners began making cash contributions to Midcontinent Express Pipeline LLC, the sole owner of the  Midcontinent Express Pipeline, for its share of the Midcontinent Express Pipeline construction costs; however, as of December 31, 2008, Kinder Morgan Energy Partners had no net investment in Midcontinent Express Pipeline LLC because in 2008, Midcontinent Express Pipeline LLC established and made borrowings under its own revolving bank credit facility in order to fund its pipeline construction costs and to make distributions to its member owners to fully reimburse them for prior contributions.

In January 2008, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement, which provides MarkWest Pioneer, L.L.C. a one-time right to purchase a 10% ownership interest in Midcontinent Express Pipeline LLC after the pipeline is fully constructed and fully placed into service—currently estimated to be August 1, 2009. If the option is exercised, Kinder Morgan Energy Partners and Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest Pioneer, L.L.C. will own the remaining 10%.

In addition to the investments listed above, significant equity investments as of December 31, 2007 included a 25% equity interest in Thunder Creek Gas Services, LLC and a 49.5% interest in Thermo Cogeneration Partnerships, L.P. and Greenhouse Holdings, LLC (“Thermo Companies”). Kinder Morgan Energy Partners sold its ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC on April 1, 2008 and we sold our interests in the Thermo Companies to Bear Stearns on January 25, 2008. Both Kinder Morgan Energy Partners’ divestiture of its investment in Thunder Creek Gas Services, LLC and our sale of our investment in the Thermo Companies are discussed in Note 10.

The amount of our recorded long-term investments is as follows:

	December 31,
	2008		2007
	(In millions)
Equity Method Investments:
NGPL PipeCo LLC	$	717.3	$	720.0
Express Pipeline System		64.9		402.1
Plantation Pipe Line Company		343.6		351.4
Thermo Companies		-		53.5
West2East Pipeline LLC		501.1		191.9
Red Cedar Gathering Company		138.9		135.6
Midcontinent Express Pipeline LLC		-		63.0
Thunder Creek Gas Services, LLC		-		37.0
Cortez Pipeline Company		13.6		14.2
Fayetteville Express Pipeline LLC		9.0		-
Horizon Pipeline Company1		-		-
Subsidiary Trusts Holding Solely Debentures of Kinder Morgan		8.6		8.6
All Others		17.2		18.9
Total Equity Investments		1,814.2		1,996.2
Gulf Opportunity Zone Bonds		13.2		-
Total Long-term Investments	$	1,827.4	$	1,996.2

______________

1 Balance at December 31, 2007 is included in the caption “Assets Held for Sale, Non-current” in the accompanying Consolidated Balance Sheet.

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Our earnings (losses) from equity investments and our amortization of excess costs over underlying fair value of net assets of these investments were as follows:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
NGPL PipeCo LLC	$	40.1		$	n/a		$	n/a		$	n/a
Cortez Pipeline Company		20.8			10.5			8.7			19.2
Express Pipeline System		8.2			14.9			5.0			17.1
Plantation Pipe Line Company		13.6			10.8			11.9			12.8
Thermo Companies		-			8.0			5.1			11.3
Red Cedar Gathering Company		26.7			16.1			11.9			36.3
Customer Works LP1		n/a			n/a			-			-
Thunder Creek Gas Services, LLC		1.3			1.2			1.0			2.5
Midcontinent Express Pipeline LLC		0.5			1.2			0.2			-
West2East Pipeline LLC		84.9			(8.2	)		(4.2	)		-
Horizon Pipeline Company		0.2			1.0			0.6			1.8
Heartland Pipeline Company2		n/a			-			-			-
All Others		4.8			1.3			0.5			3.2
Total	$	201.1		$	56.8		$	40.7		$	104.2
Amortization of Excess Costs	$	(5.7	)	$	(3.4	)	$	(2.4	)	$	(5.6	)

____________

1 This investment was part of the Terasen Inc. sale, therefore our earnings from it are included in “(Loss) Income from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations; see Note 11.

2 This investment was part of the North System sale, therefore our earnings from it are included in “(Loss) Income from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations; see Note 11.

Summarized combined unaudited financial information for our significant equity investments (listed above) is reported below (amounts represent 100% of investee financial information):

	Year Ended December 31,
	2008		2007		2006
	(In millions)
Revenues	$	2,170.4	$	738.4	$	692.1
Costs and Expenses		1,649.6		534.4		483.2
Net Income	$	520.8	$	204.0	$	208.9

	December 31,
	2008		20071
	(In millions)
Current Assets	$	501.7	$	3,566.2
Non-current Assets		13,582.1		11,469.5
Current Liabilities		3,876.4		572.3
Non-current Liabilities		5,306.0		6,078.4
Noncontrolling Interests		0.6		1.7
Partners’/Owners’ Equity		4,900.8		8,383.2

____________

1 Includes amounts associated with our NGPL business segment. In December 2007, we entered into a definitive agreement to sell an 80% ownership interest in our NGPL business segment. The closing of the sale occurred on February 15, 2008 (see Note 10).

5.  Asset Retirement Obligations

We have included $2.5 million of our total asset retirement obligations as of December 31, 2008 in the caption “Other” within “Current Liabilities” and the remaining $74.0 million in the caption “Other Long-term Liabilities and Deferred Credits:” in the accompanying Consolidated Balance Sheet. A reconciliation of the changes in our accumulated asset retirement obligations for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 is as follows:

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	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007
	(In millions)						(In millions)
Balance at Beginning of Period	$	55.0		$	53.1		$	52.5
Additions		26.2			1.2			0.2
Liabilities Settled		(8.2	)1		(0.8	)		(0.7	)
Accretion Expense		3.5			1.5			1.1
Balance at End of Period	$	76.5		$	55.0		$	53.1

____________

1 Amount includes $2.8 million settled through our 80% sale of NGPL in 2008.

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

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

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

6.  Cash Flow Information

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. “Other, Net,” presented as a component of “Cash Flows From Operating Activities” in the accompanying Consolidated Statements of Cash Flows includes, among other things, non-cash charges and credits to income including amortization of deferred revenue and amortization of gains and losses realized on the termination of interest rate swap agreements; see Note 15.

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ADDITIONAL CASH FLOW INFORMATION

Changes in Working Capital Items

(Net of Effects of Acquisitions and Sales)

Increase (Decrease) in Cash and Cash Equivalents

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Accounts Receivable	$	60.6		$	(64.3	)	$	(31.9	)	$	192.5
Materials and Supplies Inventory		(7.9	)		(8.1	)		(1.7	)		(0.5	)
Other Current Assets		11.1			(65.2	)		0.5			103.2
Accounts Payable		(99.3	)		68.7			26.3			(243.4	)
Accrued Interest		0.7			65.9			(22.5	)		56.7
Accrued Taxes		109.0			142.5			(114.0	)		(4.3	)
Other Current Liabilities		(119.1	)		(35.5	)		(59.6	)		(24.2	)
	$	(44.9	)	$	104.0		$	(202.9	)	$	80.0

Supplemental Disclosures of Cash Flow Information

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Cash Paid for
Interest (Net of Amount Capitalized)	$	649.9	$	586.5	$	381.8	$	731.6
Income Taxes Paid (Net of Refunds)1	$	657.3	$	146.4	$	133.3	$	314.9

__________

1 Income taxes paid during 2008 includes taxes paid related to prior periods.

During the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, we acquired $4.8 million, $1.2 million, $18.5 million and $6.1 million, respectively, of assets by the assumption of liabilities.

Non-cash investing activities during the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 include increases in the accrual for construction costs of $17.7 million, $83.0 million, $4.9 million and $70.5 million, respectively.

Pursuant to the purchase and sale agreement with Trans-Global Solutions, Inc., Kinder Morgan Energy Partners issued 266,813 common units in May 2007 to TGS to settle a purchase price liability related to its acquisition of bulk terminal operations from TGS in April 2005. As agreed between TGS and Kinder Morgan Energy Partners, the units were issued equal to a value of $15.0 million. Additionally, in December 2006, Kinder Morgan Energy Partners contributed 34,627 common units, representing approximately $1.7 million of value, as partial consideration for the acquisition of Devco USA L.L.C.

In March 2006, Kinder Morgan Energy Partners made a $17.0 million contribution of net assets to its investment in Coyote Gulch.

We adopted Emerging Issues Task Force No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, effective January 1, 2006 which resulted in the inclusion of the accounts, balances and results of operations of Kinder Morgan Energy Partners in our consolidated financial statements. Prior to January 1, 2006, we applied the equity method of accounting to our investment in Kinder Morgan Energy Partners. Therefore, we have included Kinder Morgan Energy Partners’ cash and cash equivalents at December 31, 2005 of $12.1 million as an “Effect of Accounting Change on Cash” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2006.

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Distributions received by our Kinder Morgan Management subsidiary from its investment in i-units of Kinder Morgan Energy Partners are in the form of additional i-units, while distributions made by Kinder Morgan Management to its shareholders are in the form of additional Kinder Morgan Management shares, see Note 2.

As discussed in Note 17 following, during the year ended December 31, 2006, we made non-cash grants of restricted shares of common stock.

7.  Transactions with Related Parties

Related-party operating revenues included in the accompanying Consolidated Statements of Operations for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $11.5 million, $6.7 million, $4.5 million and $6.1 million, respectively:

During 2008, 2007 and 2006, related-party operating revenues were primarily attributable to Horizon Pipeline Company and Plantation Pipeline Company.

The caption “Gas Purchases and Other Costs of Sales” in the accompanying Consolidated Statements of Operations includes related-party costs totaling  $5.4 million, $0.8 million, $0.3 million and $1.5 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. During 2008, related party “Gas Purchases and Other Costs of Sales” is primarily related to purchases from NGPL PipeCo LLC.

The caption “Interest Expense, Net” in the accompanying Consolidated Statements of Operations includes related-party costs totaling $5.5 million, $2.6 million, $1.8 million and $4.5 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. Related party “Interest Expenses, Net” is primarily related to interest income from Plantation Pipe Line Company and Express US Holdings LP.

Significant Investors

As discussed in Note 1, as a result of the Going Private transaction, a number of individuals and entities became significant investors in us because of their investment in Kinder Morgan Holdco LLC. By virtue of the size of their ownership interest, two of those investors became “related parties” to us as that term is defined in the authoritative accounting literature: (i) American International Group, Inc. and certain of its affiliates, including Highstar Capital (“AIG”) and (ii) Goldman Sachs Capital Partners and certain of its affiliates (“Goldman Sachs”). We enter into transactions with certain AIG affiliates in the ordinary course of their conducting insurance and insurance-related activities, although no individual transaction is, and all such transactions collectively are not, material to our consolidated financial statements. In addition, Goldman Sachs has provided, and may in the future provide, us and our affiliates investment banking services. Such activity is not material to our consolidated financial statements. We also conduct commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs. In conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs, which requires us to provide certain periodic information but does not require the posting of margin. As a result of changes in the market value of our derivative positions, we have recorded both amounts receivable from and payable to Goldman Sachs affiliates. At December 31, 2008 and December 31, 2007, the fair values of these derivative contracts are included in the accompanying Consolidated Balance Sheets within the captions indicated in the following table:

	December 31, 2008			December 31, 2007
	(In millions)
Derivative Assets (Liabilities)
Current Assets: Fair Value of Derivative Instruments	$	60.4		$	-
Assets: Fair Value of Derivative Instruments, Non-current	$	20.1		$	-
Current Liabilities: Fair Value of Derivative Instruments	$	(13.2	)	$	(239.8	)
Liabilities and Stockholders’ Equity: Fair Value of Derivative Instruments, Non-current	$	(24.1	)	$	(386.5	)

Kinder Morgan Holdco LLC

In accordance with SFAS No. 123R (revised 2007), Share-Based Payment, our parent, Kinder Morgan Holdco LLC, is required to recognize compensation expense in connection with its Class A-1 and Class B units over the expected life of such units. As a subsidiary of Kinder Morgan Holdco LLC, we and certain of our subsidiaries are allocated this compensation

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expense, which totaled $7.6 million for the year ended December 31, 2008, although none of us or any of our subsidiaries have any obligation, nor do we expect to pay any amounts in respect of such units.

Plantation Pipe Line Company

Kinder Morgan Energy Partners has a seven-year note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, its 51.17%-owned equity investee. The outstanding note receivable balance was $88.5 million and $89.7 million as of December 31, 2008 and December 31, 2007, respectively. Of these amounts, $3.7 million and $2.4 million are included within “Accounts, Notes and Interest Receivable, Net” on the accompanying Consolidated Balance Sheets as of December 31, 2008 and December 31, 2007, respectively, and the remainder is included within “Accounts, Notes and Interest Receivable, Net ” at each reporting date.

Express US Holdings LP Note Receivable

On June 30, 2008, we exchanged our C$113.6 million preferred equity interest in Express US Holdings LP for two subordinated notes from Express US Holdings LP with a combined face value of $111.4 million (C$113.6 million).

On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. This transaction included the sale of our subordinated notes described above. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer; see Note 14 for additional information relating to this sale.

As of December 31, 2008, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was$93.3 million, and we included this amount in the accompanying Consolidated Balance Sheet within the caption “Accounts, Notes and Interest Receivable, Net.”

Coyote Gas Treating, LLC

Coyote Gas Treating, LLC is a joint venture that was organized in December 1996. It is referred to as Coyote Gulch in this report. The sole asset owned by Coyote Gulch is a 250 million cubic feet per day natural gas treating facility located in La Plata County, Colorado. Prior to the contribution of Kinder Morgan Energy Partners’ ownership interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed below, Kinder Morgan Energy Partners was the managing partner and owned a 50% equity interest in Coyote Gulch, with the Southern Ute Tribe owning the remaining 50%.

On September 1, 2006, Kinder Morgan Energy Partners and the Southern Ute Tribe contributed the value of their respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value of Kinder Morgan Energy Partners’ 50% equity contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7 million, and this amount remains included within “Investments: Other” in the accompanying Consolidated Balance Sheets.

NGPL PipeCo LLC

On February 15, 2008, Kinder Morgan, Inc. entered in to an Operations and Reimbursement Agreement (“Agreement”) with Natural Gas Pipeline Company of America LLC, a wholly owned subsidiary of NGPL PipeCo LLC. The Agreement provides for Kinder Morgan, Inc. to be reimbursed, at cost, for pre-approved operations and maintenance costs, plus a $43.2 million annual general and administration fixed fee charge (“Fixed Fee”), for services provided under the Agreement. This Fixed Fee escalates at 3% each year through 2010 and is billed monthly. For the year ended December 31, 2008, these Fixed Fees totaled $38.9 million.

In addition, Kinder Morgan Energy Partners purchases transportation and storage services from NGPL PipeCo LLC. For the year ended December 31, 2008, these purchases totaled $8.1 million.

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8.  Noncontrolling Interests

As of December 31, 2008 and 2007, noncontrolling interests balances are as follows:

	December 31,
	2008		2007
	(In millions)
Kinder Morgan Energy Partners	$	2,198.2	$	1,616.0
Kinder Morgan Management		1,826.5		1,657.7
Triton Power Company LLC		39.0		29.2
Other		8.9		11.1
	$	4,072.6	$	3,314.0

During the year ended December 31, 2008, Kinder Morgan Energy Partners paid distributions of $3.89 per common unit, of which $626.6 million was paid to the public holders (represented in noncontrolling interests) of Kinder Morgan Energy Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners declared a quarterly distribution of $1.05 per common unit for the quarterly period ended December 31, 2008. The distribution was paid on February 13, 2009, to unitholders of record as of January 30, 2009.

9.  Kinder Morgan Management, LLC

On November 14, 2008, Kinder Morgan Management made a distribution of 0.021570 of its shares per outstanding share (1,646,891 total shares) to shareholders of record as of October 31, 2008, based on the $1.02 per common unit distribution declared by Kinder Morgan Energy Partners. On February 13, 2009, Kinder Morgan Management made a distribution of 0.024580 of its shares per outstanding share (1,917,189 total shares) to shareholders of record as of January 30, 2009, based on the $1.05 per common unit distribution declared by Kinder Morgan Energy Partners. These distributions are paid in the form of additional shares or fractions thereof calculated by dividing the Kinder Morgan Energy Partners’ cash distribution per common unit by the average market price of a Kinder Morgan Management share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Kinder Morgan Management has paid share distributions totaling 5,565,424, 2,402,439, 2,028,367 and 4,383,303 shares in the years ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.

On May 15, 2007, Kinder Morgan Management issued 5.7 million listed shares in a public offering at a price of $52.26 per share. Kinder Morgan Management used the net proceeds of $297.9 million from the sale to purchase 5.7 million i-units from Kinder Morgan Energy Partners.

At December 31, 2008, we owned 11.1 million Kinder Morgan Management shares representing 14.3% of Kinder Morgan Management’s outstanding shares.

10. Business Combinations, Investments and Sales

The following acquisitions were accounted for as business combinations and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary allocation of purchase price to assets acquired (and any liabilities assumed) may be adjusted to reflect the final determined amounts during a period of time following the acquisition. Although the time that is required to identify and measure the fair value of the assets acquired and the liabilities assumed in a business combination will vary with circumstances, generally our allocation period ends when we no longer are waiting for information that is known to be available or obtainable. Additionally, goodwill associated with transactions occurring prior to the Going Private transaction has been reallocated based on the purchase price paid in the Going Private transaction (See Note 1). The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.

Entrega Gas Pipeline LLC

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

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With regard to Rockies Express Pipeline LLC’s acquisition of Entrega Gas Pipeline LLC, the allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	244.6
Total Purchase Price	$	244.6
Allocation of Purchase Price
Property, Plant and Equipment	$	244.6
	$	244.6

On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas pipeline that when fully constructed, will be over 300 miles in length. The acquired assets are included in the Natural Gas Pipelines–KMP business segment.

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

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

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

Under the equity method, the costs of the investment in West2East Pipeline LLC are recorded within the “Investments” caption on the accompanying Consolidated Balance Sheets and as changes in the net assets of West2East Pipeline LLC occur (for example, earnings and dividends), we recognize our proportional share of that change in the investment account. We also record our proportional share of any accumulated other comprehensive income or loss within the “Accumulated Other Comprehensive Loss” caption in the accompanying Consolidated Balance Sheets.

In addition, Kinder Morgan Energy Partners has guaranteed its proportionate share of West2East Pipeline LLC’s debt borrowings under a $2 billion credit facility, a $2 billion commercial program and $600 million of senior notes entered into by Rockies Express Pipeline LLC. See Note 18 for additional information regarding Rockies Express Pipeline LLC’s debt.

Oil and Gas Properties

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

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

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	60.0
Liabilities Assumed		3.6
Total Purchase Price	$	63.6
Allocation of Purchase Price
Current Assets	$	0.1
Property, Plant and Equipment		63.5
	$	63.6

Terminal Assets

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

The first transaction included the acquisition of equipment and infrastructure on the Houston Ship Channel that loads and stores steel products. The acquired assets complement Kinder Morgan Energy Partners’ nearby bulk terminal facility purchased from General Stevedores, L.P. in July 2005. The second acquisition included the purchase of a rail terminal at the Port of Houston that handles both bulk and liquids products. The rail terminal complements Kinder Morgan Energy Partners’ existing Texas petroleum coke terminal operations and maximizes the value of its existing deepwater terminal by providing customers with both rail and vessel transportation options for bulk products. Thirdly, Kinder Morgan Energy Partners acquired the entire membership interest of Lomita Rail Terminal LLC, a limited liability company that owns a high-volume rail ethanol terminal in Carson, California. The terminal serves approximately 80% of the Southern California demand for reformulated fuel blend ethanol with expandable offloading/distribution capacity, and the acquisition expanded Kinder Morgan Energy Partners’ existing rail transloading operations. All of the acquired assets are included in the Terminals–KMP business segment.

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	61.6
Liabilities Assumed		0.3
Total Purchase Price	$	61.9
Allocation of Purchase Price
Current Assets	$	0.5
Property, Plant and Equipment		43.6
Goodwill		17.8
	$	61.9

A total of $17.8 million of goodwill was assigned to the Terminals–KMP business segment and the entire amount is expected to be deductible for tax purposes. Kinder Morgan Energy Partners believes the purchase price for the assets, including intangible assets, exceeded the fair value of acquired net assets and liabilities; in the aggregate, these factors represented goodwill.

Transload Services, LLC

Effective November 20, 2006, Kinder Morgan Energy Partners acquired all of the membership interests of Transload Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of approximately $16.6 million, consisting of $15.8 million in cash and $0.8 million of assumed liabilities. Transload Services, LLC is a leading provider of innovative, high quality material handling and steel processing services, operating 14 steel-related terminal facilities located in the Chicago metropolitan area and various cities in the United States. Its operations include transloading services, steel fabricating and processing, warehousing and distribution, and project staging. Specializing in steel processing and handling, Transload Services can inventory product, schedule shipments and provide customers cost-effective modes of transportation. The combined operations include over 92 acres of outside storage and 445,000 square feet of covered storage that offers

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customers environmentally controlled warehouses with indoor rail and truck loading facilities for handling temperature and humidity sensitive products. The acquired assets are included in the Terminals–KMP business segment, and the acquisition further expanded and diversified Kinder Morgan Energy Partners’ existing terminals’ materials services (rail transloading) operations.

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	15.8
Liabilities Assumed		0.8
Total Purchase Price	$	16.6
Allocation of Purchase Price
Current Assets	$	1.6
Property, Plant and Equipment		6.6
Goodwill		8.4
	$	16.6

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

Devco USA L.L.C.

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

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	4.8
Issuance of Common Units		1.6
Liabilities Assumed		0.9
Total Purchase Price	$	7.3
Allocation of Purchase Price
Current Assets	$	0.8
Deferred Charges and Other Assets		6.5
	$	7.3

Roanoke, Virginia Products Terminal

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

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The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	6.4
Total Purchase Price	$	6.4
Allocation of Purchase Price
Property, Plant and Equipment	$	6.4
	$	6.4

Interest in Cochin Pipeline

Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that it 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 Kinder Morgan Energy Partners for certain pipeline integrity management costs over a five-year period in an aggregate amount not to exceed $50 million. Upon closing, Kinder Morgan Energy Partners became the operator of the pipeline.

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

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	5.5
Notes Payable (Fair Value)		42.3
Total Purchase Price	$	47.8
Allocation of Purchase Price
Property, Plant and Equipment	$	47.8
	$	47.8

Vancouver Wharves Terminal

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

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

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	38.8
Assumed Liabilities		20.7
Total Purchase Price	$	59.5
Allocation of Purchase Price
Current Assets	$	6.1
Property, Plant and Equipment		53.4
	$	59.5

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Marine Terminals, Inc.

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

During 2008, Kinder Morgan Energy Partners paid an additional $0.5 million for purchase price settlements, and made purchase price adjustments to reflect final fair value of acquired assets and final expected value of assumed liabilities. Kinder Morgan Energy Partners’ 2008 adjustments primarily reflected changes in the allocation of the purchase cost to intangible assets acquired. Based on Kinder Morgan Energy Partners’ estimate of fair market values, we allocated $60.8 million of the combined purchase price to “Property, Plant and Equipment, Net,” $21.7 million to “Other Intangibles, Net,” $18.6 million to “Goodwill,” and $1.0 million to “Current Assets: Other” and “Deferred Charges and Other Assets.”

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

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

The allocation of the purchase price to assets acquired and liabilities assumed was as follows (in millions):

Purchase Price
Cash Paid, Including Transaction Costs	$	100.8
Assumed Liabilities		1.3
Total Purchase Price	$	102.1
Allocation of Purchase Price
Current Assets	$	0.2
Property, Plant and Equipment		60.8
Deferred Charges and Other		22.5
Goodwill		18.6
	$	102.1

Wilmington, North Carolina Liquids Terminal

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

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Purchase Price
Cash Paid, Including Transaction Costs	$	11.8
Assumed Liabilities		0.9
Total Purchase Price	$	12.7
Allocation of Purchase Price
Property, Plant and Equipment	$	5.9
Goodwill		6.8
	$	12.7

Phoenix, Arizona Products Terminal

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

Purchase Price
Cash Paid, Including Transaction Costs	$	27.5
Total Purchase Price	$	27.5
Allocation of Purchase Price
Property, Plant and Equipment	$	27.5
	$	27.5

Investment in Rockies Express Pipeline

In 2008, Kinder Morgan Energy Partners made capital contributions of $306.0 million to West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to partially fund its Rockies Express Pipeline construction costs. This cash contribution was recorded as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008, and it was included within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008. Kinder Morgan Energy Partners owns a 51% equity interest in West2East Pipeline LLC.

Midcontinent Express Pipeline LLC

During 2008, Kinder Morgan Energy Partners made capital contributions of $27.5 million to Midcontinent Express Pipeline LLC (“Midcontinent Express Pipeline”) to partially fund its Midcontinent Express Pipeline construction costs. This cash contribution has been recorded as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008 and has been included within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008. Kinder Morgan Energy Partners owns a 50% equity interest in Midcontinent Express Pipeline LLC.

Kinder Morgan Energy Partners received, in 2008, an $89.1 million return of capital from Midcontinent Express Pipeline LLC. In February 2008, Midcontinent Express Pipeline LLC entered into and then made borrowings under a new $1.4 billion three-year, unsecured revolving credit facility due February 28, 2011. Midcontinent Express Pipeline LLC then made distributions (in excess of cumulative earnings) to its two member owners to reimburse them for prior contributions made to fund its pipeline construction costs, and this cash receipt has been included in “Cash Flows from Investing Activities: Distributions from Equity Investees” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008.

Fayetteville Express Pipeline LLC

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

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

In the fourth quarter of 2008, Kinder Morgan Energy Partners made capital contributions of $9.0 million to Fayetteville Express Pipeline LLC to fund its proportionate share of certain pre-construction pipeline costs. We included this cash contribution as an increase to “Investments” in the accompanying Consolidated Balance Sheet as of December 31, 2008, and we included it within “Cash Flows from Investing Activities: Contributions to Investments” in the accompanying Consolidated Statement of Cash Flows for the year ended December 31, 2008.

Pro Forma Information

Pro forma information regarding consolidated income statement information that assumes all of the acquisitions we have made and joint ventures we have entered into since January 1, 2007, including the ones listed above, had occurred as of January 1, 2007, is not materially different from the information presented in the accompanying Consolidated Statements of Operations.

Sales

In connection with the August 28, 2008 sale to Kinder Morgan Energy Partners of our 33 1/3% ownership interest in the Express pipeline system and our full ownership of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of common units to us. The units were issued August 28, 2008, and as agreed between Kinder Morgan Energy Partners and us, were valued at $116.0 million. We accounted for this transaction as a transfer of net assets between entities under common control. Kinder Morgan Energy Partners recognized these assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. For more information on this transaction; see Note 7.

Effective April 1, 2008, Kinder Morgan Energy Partners sold its 25% ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn Virginia Corporation. Prior to the sale, we accounted for the investment in Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek, under the equity method of accounting and included its financial results within the Natural Gas Pipelines–KMP business segment. In the second quarter of 2008, Kinder Morgan Energy Partners received cash proceeds, net of closing costs and settlements, of approximately $50.7 million for the investment and used the proceeds from this sale to reduce the commercial paper borrowings. Due to the fair market valuation resulting from the Going Private transaction (see Note 1), the consideration Kinder Morgan Energy Partners received from the sale of its North System was equal to its carrying value; therefore no gain or loss was recorded on this disposal transaction.

On February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC (formerly MidCon Corp.), which owns Natural Gas Pipeline Company of America LLC and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc. (“Myria”) for approximately $2.9 billion. We also received approximately $3.0 billion of cash previously held in escrow related to a notes offering by NGPL PipeCo LLC in December 2007, the net proceeds of which were distributed to us principally as repayment of intercompany indebtedness and partially as a dividend, immediately prior to the closing of the sale to Myria. Pursuant to the purchase agreement, Myria acquired all 800 Class B shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate of investors led by Babcock & Brown, an international investment and specialized fund and asset management group. The total proceeds from this sale of $5.9 billion were used to pay off the entire outstanding balances of our senior secured credit facility’s Tranche A and Tranche B term loans, to repurchase $1.67 billion of our outstanding debt securities and to reduce balances outstanding under our $1.0 billion revolving credit facility (see Note 14).

In January 2008, we completed the sale of our interests in three natural gas-fired power plants in Colorado to Bear Stearns. We received proceeds of $63.1 million.

During 2007, we completed the sales of (i) our U.S.-based retail natural gas distribution and related operations, (ii) Terasen Inc., our Canada-based retail natural gas distribution operations, which we previously referred to as the Terasen Gas business segment and (iii) Terasen Pipelines (Corridor) Inc. Additionally, in 2007 Kinder Morgan Energy Partners completed the sale of its North System and its 50% ownership interest in the Heartland Pipeline Company. Note 11 contains additional information regarding these discontinued operations.

In December 2007, we sold the remainder of our surplus power equipment for $3.0 million (net of marketing fees.) We did not recognize any gain or loss associated with this sale.

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On April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain pipeline system from us. We accounted for this transaction as a transfer of net assets between entities under common control. Kinder Morgan Energy Partners recognized the Trans Mountain assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. As discussed in Note 3, based on an evaluation of the fair value of the Trans Mountain pipeline system, a goodwill impairment charge of approximately $377.1 million was recorded in 2007.

In December 2006, we sold power generation equipment for $13.3 million (net of marketing fees). We recognized a pre-tax gain of $1.2 million associated with this sale. During the first quarter of 2006, we sold power generation equipment for $7.5 million (net of marketing fees). We recognized a pre-tax gain of $1.5 million associated with this sale. This equipment was a portion of the equipment that became surplus as a result of our decision to exit the power development business.

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

Additionally, upon the sale of Kinder Morgan Energy Partners’ Douglas gathering system, Kinder Morgan Energy Partners reclassified a net loss of $2.9 million from “Accumulated Other Comprehensive Loss” into net income on those derivative contracts that effectively hedged uncertain future cash flows associated with forecasted Douglas gathering transactions. We included the net amount of the gain, $15.1 million, within the caption “Operating Costs and Expenses: Other Expenses (Income)” in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006.

Investments

Kinder Morgan Energy Partners spent approximately $333.5 million in 2008 for its proportionate share of discretionary capital expenditures for both the Rockies Express and Midcontinent Express natural gas pipeline projects, and it expects to spend a combined $1.5 billion for its share of discretionary capital expenditures for both projects in 2009.

During 2007, Kinder Morgan Energy Partners made incremental investments of $202.7 million for its share of construction costs of the Rockies Express Pipeline. Kinder Morgan Energy Partners owns a 51% equity interest through West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC. (See note 4 for further information regarding this equity investment.)

During 2007, Kinder Morgan Energy Partners made incremental investments of $61.6 million for its share of construction costs of the Midcontinent Express Pipeline. Kinder Morgan Energy Partners owns a 50% equity interest in the approximate $2.2 billion, 500-mile interstate natural gas pipeline that will extend between Bennington, Oklahoma and Butler, Alabama.

In December 2006, Kinder Morgan Energy Partners issued 34,627 common units as partial consideration for the acquisition of Devco USA L.L.C. This transaction had the associated effects of increasing the noncontrolling interests associated with Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by $110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii) paid-in capital by $18,589.

11. Discontinued Operations

North System Natural Gas Liquids Pipeline System - In October 2007, Kinder Morgan Energy Partners completed the sale of its North System and its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6 million in cash. For the year ended December 31, 2008, Kinder Morgan Energy Partners paid $2.4 million to ONEOK Partners, L.P. to fully settle both the sale of working capital items and the allocation of pre-acquisition investee distributions, and to partially settle the sale of liquids inventory balances. Due to the fair market valuation resulting from the Going Private transaction (see Note 1), the consideration Kinder Morgan Energy Partners received from the sale of its North System was equal to its carrying value; therefore no gain or loss was recorded on this disposal transaction. The North System consists of an approximately 1,600-mile interstate common carrier pipeline system that delivers natural gas liquids and refined petroleum products from south central Kansas to the Chicago area. Also included in the sale were eight propane truck-loading terminals located at various points in three states along the pipeline system, and one multi-product terminal complex located in Morris, Illinois. All of these assets were included in our Products Pipelines–KMP business segment.

Terasen Pipelines (Corridor) Inc. - In June 2007, we completed the sale of Terasen Pipelines (Corridor) Inc. (“Corridor”) to Inter Pipeline Fund, a Canada-based company. Corridor transports diluted bitumen from the Athabasca Oil Sands Project near Fort McMurray, Alberta, to the Scotford Upgrader near Fort Saskatchewan, Alberta. The sale did not include any other assets of Kinder Morgan Canada (formerly Terasen Pipelines). The sale price was approximately $711 million (C$760

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million) plus the buyer’s assumption of all of the debt related to Corridor, including the debt associated with the expansion taking place on Corridor at the time of the sale. The consideration was equal to Corridor’s carrying value, therefore no gain or loss was recorded on this disposal transaction.

Terasen Inc. - We closed the sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of approximately $3.4 billion (C$3.7 billion) including cash plus the buyers’ assumption of debt. The sale did not include the assets of Kinder Morgan Canada (formerly Terasen Pipelines) discussed in the preceding paragraph. We recorded a book gain on this disposition of $55.7 million in the second quarter of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes. Approximately $223.3 million of this loss was utilized to reduce capital gains principally associated with the sale of our U.S.-based retail gas operations (see below) resulting in a tax benefit of approximately $82.2 million. The remaining capital loss carryforward of $775.3 million was utilized to reduce the capital gain associated with our sale of an 80% ownership interest in NGPL PipeCo LLC (see Note 10).

Natural Gas Distribution and Retail Operations - In March 2007, we completed the sale of our U.S.-based retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company and Alinda Investments LLC for $710 million and an adjustment for working capital. In conjunction with this sale, we recorded a pre-tax gain of $251.8 million (net of $3.9 million of transaction costs) in the first quarter of 2007. Our Natural Gas Pipelines–KMP business segment (i) provides natural gas transportation and storage services and sells natural gas to and (ii) receives natural gas transportation and storage services, natural gas and natural gas liquids and other gas supply services from the discontinued U.S.-based retail natural gas distribution business. These transactions are continuing after the sale of this business and will likely continue to a similar extent into the future. For the five months ended May 31, 2007, revenues and expenses of our continuing operations totaling $3.1 million and $1.2 million, respectively for products and services sold to and purchased from our discontinued U.S.-based retail natural gas distribution operations prior to its sale in March 2007, have been eliminated in the accompanying Consolidated Statements of Operations. We are currently receiving fees from SourceGas, a subsidiary of General Electric Company, to provide certain administrative functions for a limited period of time and for the lease of office space. We do not have any significant continuing involvement in or retain any ownership interest in these operations and, therefore, the continuing cash flows discussed above are not considered direct cash flows of the disposed assets.

Earnings of Discontinued Operations - The financial results of discontinued operations have been reclassified for all periods presented and reported in the caption, “Income (Loss) from Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements of Operations. Summarized financial results of these operations are as follows:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Operating Revenues	$	-		$	24.1		$	921.8		$	1,999.3
Earnings (Loss) from Discontinued Operations Before Income Taxes	$	(0.9	)	$	(10.2	)	$	393.2		$	(530.6	)
Income Taxes		-			8.7			(94.6	)		2.1
Earnings (Loss) from Discontinued Operations	$	(0.9	)	$	(1.5	)	$	298.6		$	(528.5	)

The cash flows attributable to discontinued operations are included in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 in the captions “Net Cash Flows (Used in) Provided by Discontinued Operations,” “Net Cash Flows Provided by (Used in) Discontinued Investing Activities” and “Net Cash Flows Provided by (Used in) Discontinued Financing Activities.”

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12. Property, Plant and Equipment

Classes and Depreciation

As of December 31, 2008 and 2007, investments in property, plant and equipment are as follows:

	December 31,
	2008			2007
Kinder Morgan, Inc.
Natural Gas and Liquids Pipelines	$	-		$	16.1
Electric Generation		-			10.3
General and Other		44.4			43.9
Kinder Morgan Energy Partners1
Natural Gas, Liquids and Carbon Dioxide Pipelines		5,641.5			6,572.6
Pipeline and Terminals Station Equipment		7,577.0			5,596.0
General and Other		2,084.5			1,095.9
Accumulated Amortization, Depreciation and Depletion		(979.0	)		(277.0	)
		14,368.4			13,057.8
Land		201.7			297.3
Natural Gas, Liquids (including Line Fill) and Transmix Processing		210.3			168.2
Construction Work in Process		1,329.4			1,280.6
Property, Plant and Equipment, Net	$	16,109.8		$	14,803.9

____________

1 Includes the allocation of purchase accounting adjustments associated with the Going Private transaction (see Note 1).

Property Casualties

2005 Hurricanes

In 2006, Kinder Morgan Energy Partners reached settlements with its insurance carriers on all property damage claims related to the 2005 hurricanes and recognized a casualty gain of $15.2 million, excluding repair and clean-up expenses. After proceeds from insurance carrier claim reimbursements of $8.0 million and $13.1 million in 2007 and 2006 respectively, which are included in the caption “Property Casualty Indemnifications” within investing activities in the accompanying Consolidated Statements of Cash Flows, Kinder Morgan Energy Partners’ total increase in net income, net of repair and clean-up expenses, was $8.6 million in 2006 from the 2005 hurricanes.

2008 Hurricanes and Fires

Kinder Morgan Energy Partners realized a combined $11.1 million of incremental expenses for clean-up and asset damage from hurricanes Hanna, Gustav and Ike, excluding estimates for lost business and lost revenues. Additionally, fire damage at three separate terminal locations resulted in $7.2 million of incremental expenses, excluding estimates for lost business and lost revenues. Of these incremental expenses for the hurricanes and terminal fires, $10.5 million and $5.3 million were included within the captions “Operations and Maintenance” and “Other Expenses (Income),” respectively, in the accompanying Consolidated Statement of Operations for the year ended December 31, 2008.

13. Income Taxes

The components of income (loss) before income taxes from continuing operations are as follows:

	Successor Company					Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)					(In millions)
United States	$	(2,978.7	)	$	511.8	$	369.9		$	1,277.8
Foreign		80.7			1.7		(376.4	)		(17.3	)
Total	$	(2,898.0	)	$	513.5	$	(6.5	)	$	1,260.5

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Components of the income tax provision applicable to continuing operations for federal and state income taxes are as follows:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Current Tax Provision
U.S.
Federal	$	786.6		$	268.6		$	(7.0	)	$	246.6
State		18.6			25.1			3.2			10.2
Foreign		(4.5	)		23.5			0.6			18.3
		800.7			317.2			(3.2	)		275.1
Deferred Tax Provision
U.S.
Federal		(439.5	)		(95.2	)		134.0			46.9
State		11.5			0.5			6.4			(36.3	)
Foreign		(68.4	)		4.9			(1.7	)		0.2
		(496.4	)		(89.8	)		138.7			10.8
Total Tax Provision	$	304.3		$	227.4		$	135.5		$	285.9
Effective Tax Rate		10.5	%		44.3	%		2,084.6	%		22.7	%

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

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Federal Income Tax Rate		(35.0	%)		35.0	%		(35.0	%)		35.0	%
Increase (Decrease) as a Result of:
Nondeductible Goodwill Impairment		48.7	%		(0.7	)		2,039.8	%		-
Terasen Acquisition Financing Structure		-			-			(257.0	%)		(3.6	%)
Nondeductible Going Private Costs		-			-			475.6	%		-
Deferred Tax Rate Change		0.6	%		-			(0.2	)		(3.0	%)
Foreign Earnings Subject to Different Tax Rates		(2.4	%)		5.4	%		129.5	%		1.8	%
Net Effects of Consolidating Kinder Morgan Energy Partners’ United States Income Tax Provision		(2.7	%)		2.8	%		(348.3	%)		(7.3	%)
State Income Tax, Net of Federal Benefit		0.6	%		2.2	%		105.6	%		1.3	%
Other		0.7	%		(0.4	%)		(25.4	%)		(1.5	%)
Effective Tax Rate		10.5	%		44.3	%		2,084.6	%		22.7	%

Income taxes included in the financial statements were composed of the following:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Continuing Operations	$	304.3		$	227.4		$	135.5		$	285.9
Discontinued Operations		(0.4	)		(8.7	)		94.6			(2.1	)
Equity Items		122.2			(219.4	)		(51.7	)		(22.2	)
Total	$	426.1		$	(0.7	)	$	178.4		$	261.6

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Deferred tax assets and liabilities result from the following:

	December 31, 2008		December 31, 2007
	(In millions)		(In millions)
Deferred Tax Assets
Postretirement Benefits	$	79.8	$	12.1
Book Accruals		14.3		-
Derivatives		-		270.9
Capital Loss Carryforwards		-		279.5
Interest Rate Swaps		7.0		-
Other		7.9		-
Total Deferred Tax Assets		109.0		562.5
Deferred Tax Liabilities
Property, Plant and Equipment		160.0		125.2
Investments		1,937.2		1,909.0
Book Accruals		-		62.1
Derivative Instruments		5.7		-
Rate Matters		-		0.4
Prepaid Pension Costs		16.6		17.9
Assets/Liabilities Held for Sale		-		897.5
Debt Adjustment		23.0		-
Other		47.8		66.2
Total Deferred Tax Liabilities		2,190.3		3,078.3
Net Deferred Tax Liabilities	$	2,081.3	$	2,515.8
Current Deferred Tax Asset	$	-	$	-
Current Deferred Tax Liability		-		666.4
Non-current Deferred Tax Liability		2,081.3		1,849.4
Net Deferred Tax Liabilities	$	2,081.3	$	2,515.8

During 2007, our sale of Terasen Inc. resulted in a capital loss of $998.6 million of which approximately $223.3 million was utilized to reduce capital gain principally associated with the sale of our U.S.-based retail natural gas operations. The remaining capital loss was carried forward and utilized to reduce the capital gain on the sale of our 80% ownership interest in the NGPL business segment.

In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, (“FIN No. 48”) which became effective January 1, 2007. FIN No. 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 No. 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

We adopted the provisions of FIN No. 48 on January 1, 2007. The total amount of unrecognized tax benefits as of the date of adoption was $63.1 million. We recorded a $4.8 million decrease to the opening balance of retained earnings as a result of the implementation of FIN No. 48.

A reconciliation of our gross unrecognized tax benefit excluding interest and penalties for the years ended December 31, 2008 and 2007 is as follows (in millions):

	2008			2007
Balance at beginning of period	$	41.5		$	63.1
Additions based on current year tax positions		2.1			9.8
Additions based on prior year tax positions		15.9			0.5
Reductions based on settlements with taxing authority		(10.2	)		(21.4	)
Reductions due to lapse in statue of limitations		(3.7	)		(2.7	)
Reductions for tax positions related to prior year		(19.4	)		(7.8	)
Balance at end of period	$	26.2		$	41.5

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Our continuing practice is to recognize interest and/or penalties related to income tax matters in income tax expense, and as of December 31, 2007, we had $8.1 million of accrued interest and no accrued penalties. As of December 31, 2008, we had $2.9 million of accrued interest and $0.8 million ofaccrued penalties. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by $4.8 million during the next twelve months, and that approximately$34.1 million included in the total$26.2 million of unrecognized tax benefits on the accompanying Consolidated Balance Sheet as of December 31, 2008 would affect our effective tax rate in future periods in the event those unrecognized tax benefits were recognized. Such amounts exclude interest, while the latter amount of $26.6 million includes both temporary and permanent differences.

We are subject to taxation, and have tax years open to examination for the periods 2003-2008 in the United States and Mexico, 2004-2008 in Canada, and 1999-2008 in various states.

14. Financing

Notes Payable

We and our consolidated subsidiaries had the following unsecured credit facilities outstanding at December 31, 2008.

Credit Facilities

Kinder Morgan, Inc.—$1.0 billion, six-year secured revolver, due May 2013

Kinder Morgan Energy Partners—$1.85 billion, five-year unsecured revolver, due August 2010

The following are short-term borrowings, issued by the below-listed borrowers, where the commercial paper is supported by each borrower’s respective credit facilities. The short-term borrowings shown in the tables below, totaling $8.8 million and $888.1 million, respectively, are reported in the caption “Notes Payable” in the accompanying Balance Sheets at December 31, 2008 and 2007, respectively.

	December 31, 2008
	Short-term Borrowings Outstanding Under Revolving Credit Facility		Commercial Paper Outstanding		Weighted-average Interest Rate of Short-term Debt Outstanding
	(In millions)
Kinder Morgan, Inc.
$1.0 billion	$	8.8		-		3.38	%
Kinder Morgan Energy Partners
$1.85 billion	$	-		-		-	%

	December 31, 2007
	Short-term Borrowings Outstanding Under Revolving Credit Facility		Commercial Paper Outstanding		Weighted-average Interest Rate of Short-term Debt Outstanding
	(In millions)
Kinder Morgan, Inc.
$1.0 billion	$	299.0	$	-		6.42	%
Kinder Morgan Energy Partners
$1.85 billion	$	-	$	589.1		5.58	%

The weighted average interest rates on our outstanding borrowings under the $1.0 billion credit facility for the year ended December 31, 2008 and seven months ended December 31, 2007 were approximately 4.43% and 6.61%, respectively. The weighted average interest rate on Terasen Pipelines (Corridor) Inc.’s short term debt was 4.33% for the seven months ended December 31, 2007. For the five months ended May 31, 2007, the weighted average interest rates on outstanding borrowings under Kinder Morgan, Inc.’s $800 million credit facility, which was terminated on May 30, 2007, was 5.81% and the outstanding borrowings under the Terasen Inc., Terasen Gas Inc. and Terasen Pipelines (Corridor) Inc.’s respective credit facilities were 4.34%, 4.23% and 4.24% . Terasen Inc, including Terasen Gas Inc., and Terasen Pipelines (Corridor) Inc. were sold on May 17, 2007 and June 15, 2007 respectively. Accordingly, the average short-term debt associated with these

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facilities for the seven months ended December 31, 2007 and five months ended May 31, 2007 are only through the respective dates of sale.

The weighted average interest rates under Kinder Morgan Energy Partners’ credit facility for the year ended December 31, 2008 was 3.47%. Weighted average interest rates under Kinder Morgan Energy Partners’ commercial paper program for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 were 3.47%, 5.46% and 5.40%, respectively. Kinder Morgan Energy Partners currently does not have access to the commercial paper market.

The Kinder Morgan, Inc. $1.0 billion six-year senior secured revolving credit facility matures on May 30, 2013 and includes a sublimit of $300 million for the issuance of letters of credit and a sublimit of $50 million for swingline loans. Kinder Morgan, Inc. does not have a commercial paper program. This revolving credit facility, as part of a $5.755 billion credit agreement used to finance the Going Private transaction, replaced an $800 million five-year credit facility dated August 5, 2005. The $5.755 billion credit agreement dated May 30, 2007, is with a syndicate of financial institutions and Citibank, N.A., as administrative agent and included three tranches of term loan facilities, which were subsequently retired.

The credit agreement permits one or more incremental increases under the revolving credit facility or an addition of new term facilities in an aggregate amount of up to $1.5 billion, provided certain conditions are met. Such additional capacity is uncommitted. Additionally, the revolving credit facility allows for one or more swingline loans from Citibank, N.A., in its individual capacity, up to an aggregate amount of $50.0 million provided certain conditions are met.

Our obligations under the credit agreement and certain existing notes issued by us and Kinder Morgan Finance Company, LLC, the sale of which were registered under the Securities Act of 1933, as amended, are secured, subject to specified exceptions, by a first-priority lien on all the capital stock of each of our wholly owned subsidiaries (limited, in the case of foreign subsidiaries, to 65% of the capital stock of such subsidiaries) and by perfected security interests in, and mortgages on, substantially all of our and our subsidiaries’ tangible and intangible assets (including, without limitation, accounts (other than deposit accounts or other bank or securities accounts), inventory, equipment, investment property, intellectual property, other general intangibles, material fee-owned real property (other than pipeline assets and any leasehold property) and proceeds of the foregoing). None of the assets of Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy Partners or their respective subsidiaries are pledged as security as part of this financing.

Loans under the revolving credit facility will bear interest, at Kinder Morgan, Inc.’s option, at:

· a rate equal to LIBOR (London Interbank Offered Rate) plus an applicable margin, or

· a rate equal to the higher of (a) U.S. prime rate and (b) the federal funds effective rate plus 0.50%, in each case, plus an applicable margin.

The swingline loans will bear interest at:

· a rate equal to the higher of (a) U.S. prime rate and (b) the federal funds effective rate plus 0.50%, in each case, plus an applicable margin.

The applicable margin for the revolving credit facility is subject to decrease pursuant to a leverage-based pricing grid. In addition, the credit agreement provides for customary commitment fees and letter of credit fees under the revolving credit facility. Based on our ratio, as defined in the credit agreement, of consolidated total debt to earnings before interest, income taxes and depreciation and amortization at December 31, 2008, our facility fee was 25 basis points. The credit agreement contains customary terms and conditions and is unconditionally guaranteed by each of our wholly owned material domestic restricted subsidiaries, to the extent permitted by applicable law and contract. Voluntary prepayments can be made at any time on revolving credit loans and swingline loans, in each case without premium or penalty, and on LIBOR Loans (as defined in the credit agreement) on the interest payment date without premium or penalty.

Our $5.755 billion credit agreement includes the following restrictive covenants:

· total debt divided by earnings before interest, income taxes, depreciation and amortization for (i) the test period ending December 31, 2007 may not exceed 8.75:1.00, (ii) January 1, 2008 to December 31, 2008 may not exceed 8.00:1.00, (iii) January 1, 2009 to December 31, 2009 may not exceed 7.00:1.00 and (iv) thereafter may not exceed 6.00:1.00;

· certain limitations on indebtedness, including payments and amendments;

· certain limitations on entering into mergers, consolidations, sales of assets and investments;

· limitations on granting liens; and

· prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend.

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The Kinder Morgan Energy Partners $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 the credit facility can be used for partnership purposes and as a backup for Kinder Morgan Energy Partners’ commercial paper program. As of December 31, 2008 and 2007, respectively, there were no borrowings under the credit facility.

Kinder Morgan Energy Partners’ five-year credit facility is with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent. The credit facility permits Kinder Morgan Energy Partners to obtain bids for fixed rate loans from members of the lending syndicate. Interest on the credit facility accrues at Kinder Morgan Energy Partners’ option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) London Interbank Offered Rate (“LIBOR”), plus a margin, which varies depending upon the credit rating of Kinder Morgan Energy Partners’ long-term senior unsecured debt.

Kinder Morgan Energy Partners’ credit facility included the following restrictive covenants as of December 31, 2008:

· total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed:

· 5.5, in the case of any such period ended on the last day of (i) a fiscal quarter in which Kinder Morgan Energy Partners makes any Specified Acquisition, or (ii) the first or second fiscal quarter next succeeding such a fiscal quarter; or

· 5.0, in the case of any such period ended on the last day of any other fiscal quarter;

· certain limitations on entering into mergers, consolidations and sales of assets;

· limitations on granting liens; and

· prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.

In addition to normal repayment covenants, under the terms of Kinder Morgan Energy Partners’ credit facility, the occurrence at any time of any of the following would constitute an event of default: (i) Kinder Morgan Energy Partners’ failure to make required payments of any item of indebtedness or any payment in respect of any hedging agreement, provided that the aggregate outstanding principal amount for all such indebtedness or payment obligations in respect of all hedging agreements is equal to or exceeds $75 million, (ii) Kinder Morgan G.P., Inc.’s failure to make required payments of any item of indebtedness, provided that the aggregate outstanding principal amount for all such indebtedness is equal to or exceeds $75 million, (iii) adverse judgments rendered against Kinder Morgan Energy Partners for the payment of money in an aggregate amount in excess of $75 million, if this same amount remains undischarged for a period of thirty consecutive days during which execution shall not be effectively stayed and (iv) voluntary or involuntary commencements of any proceedings or petitions seeking Kinder Morgan Energy Partners’ liquidation, reorganization or any other similar relief under any federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Excluding the relatively non-restrictive specified negative covenants and events of defaults, Kinder Morgan Energy Partners’ credit facility does not contain any provisions designed to protect against a situation where a party to an agreement is unable to find a basis to terminate that agreement while its counterparty’s impending financial collapse is revealed and perhaps hastened through the default structure of some other agreement. The credit facility also does not contain a material adverse change clause coupled with a lockbox provision; however, the facility does provide that the margin Kinder Morgan Energy Partners will pay with respect to borrowings and the facility fee that Kinder Morgan Energy Partners will pay on the total commitment will vary based on Kinder Morgan Energy Partners’ senior debt investment rating. None of Kinder Morgan Energy Partners’ debt is subject to payment acceleration as a result of any change to its credit ratings.

On September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One Lehman entity was a lending institution that provided a portion of Kinder Morgan Energy Partners’, Rockies Express’ and Mid Continent Express’ respective credit facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is a party to the credit facilities, has not met its obligations to lend under those agreements. As such, the commitments have been effectively reduced by $63 million, $41 million and $100 million, respectively, to $1.8 billion, $2.0 billion and $1.3 billion. The commitments of the other banks remain unchanged and the facilities are not defaulted.

Long-term Debt

Since we are accounting for the Going Private transaction (see Note 1) as a purchase business combination that is required to be “pushed-down” to us, we have adjusted the carrying value of our long-term debt securities to reflect their fair values, to the extent of Kinder Morgan, Inc.’s economic ownership interest, at the time of the Going Private transaction and the adjustments are being amortized over the remaining lives of the debt securities. The unamortized fair value adjustment balances reflected within the caption “Long-term Debt” in the accompanying Consolidated Balance Sheet at December 31, 2008 were $46.0 million and $6.7 million, representing a decrease to the carrying value of our long-term debt and an increase

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in the value of our interest rate swaps, respectively. Our long-term debt balances at December 31, 2008 and 2007 of $12,126.8 million and $15,297.4 million, respectively, consisted of the balances shown in the table below.

	December 31,
	2008		2007
	(In millions)
Kinder Morgan, Inc.
Debentures
6.50% Series, Due 2013	$	6.1	$	30.1
6.67% Series, Due 2027		7.0		148.3
7.25% Series, Due 2028		32.0		494.3
7.45% Series, Due 2098		25.9		146.3
Senior Notes
6.50% Series, Due 2012		846.2		1,010.5
5.15% Series, Due 2015		233.3		231.2
Senior Secured Credit Term Loan Facilities
Tranche A Term Loan, Due 2013		-		997.5
Tranche B Term Loan, Due 2014		-		3,191.7
Deferrable Interest Debentures Issued to Subsidiary Trusts
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027		15.8		106.9
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028		19.9		176.2
Unamortized Gain on Termination of Interest Rate Swap		6.4		11.5
Kinder Morgan Finance Company, LLC
5.35% Series, Due 2011		742.0		738.5
5.70% Series, Due 2016		806.6		801.9
6.40% Series, Due 2036		33.8		503.8
Carrying Value Adjustment for Interest Rate Swap1		-		23.2
Unamortized Gain on Termination of Interest Rate Swap		12.8		11.6
Kinder Morgan G.P., Inc.
$1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock		100.0		100.0
Kinder Morgan Energy Partners
Senior Notes
6.30% Series, Due 2009		250.1		250.9
7.50% Series, Due 2010		253.8		255.7
6.75% Series, Due 2011		707.6		710.6
7.125% Series, Due 2012		458.7		461.1
5.85% Series, Due 2012		500.0		500.0
5.00% Series, Due 2013		491.3		489.8
5.125% Series, Due 2014		490.2		488.9
6.00% Series, Due 2017		597.8		597.5
5.95% Series Due 2018		975.0		-
9.00% Series Due 2019		500.0		-
7.40% Series, Due 2031		310.3		310.5
7.75% Series, Due 2032		316.4		316.7
7.30% Series, Due 2033		513.9		514.1
5.80% Series, Due 2035		477.4		477.1
6.50% Series, Due 2037		395.8		395.7
6.95% Series, Due 2038		1,175.0		550.0
Other		1.1		1.1
Carrying Value Adjustment for Interest Rate Swaps1		754.2		146.2
Unamortized Gain on Termination of Interest Rate Swap		197.6		7.2
Central Florida Pipe Line LLC
7.84% Series, Due 2008		-		5.0
Arrow Terminals L.P.
Illinois Development Finance Authority Adjustable Rate Industrial Development Revenue Bonds, Due 2010, weighted-average interest rate of 2.52% for the year ended December 31, 2008 (3.77% for the seven months ended December 31, 2007 and 3.87% for the five months ended May 31, 2007)		5.3		5.3

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Kinder Morgan Operating, L.P. “A” and Kinder Morgan Canada
5.40% Note, Due 2012		36.6			44.6
Kinder Morgan Texas Pipeline, L.P.
8.85% Series, Due 2014		37.0			43.2
Kinder Morgan Liquids Terminals LLC
New Jersey Economic Development Revenue Refunding Bonds, Due 2018, weighted-average interest rate of 1.63% for the year ended December 31, 2008(3.48 % for the seven months ended December 31, 2007 and 3.63% for the five months ended May 31, 2007)		25.0			25.0
Kinder Morgan Operating, L.P. “B”
Jackson-Union Counties, Illinois Regional Port District Tax-exempt Floating Rate Bonds, Due 2024, weighted-average interest rate of 2.96% for the year ended December 31, 2008 (3.68% for the seven months ended December 31, 2007 and 3.59% for the five months ended May 31, 2007)		23.7			23.7
Other		0.2			0.2
International Marine Terminals
Plaquemines Port, Harbor and Terminal District (Louisiana) Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds, Due 2025, weighted-average interest rate of 2.50% for the year ended December 31, 2008 (3.65% for the seven months ended December 31, 2007 and 3.59% for the five months ended May 31, 2007)		40.0			40.0
Gulf Opportunity Zone Bonds
Kinder Morgan Louisiana Pipeline LLC
6.00% Louisiana Community Development Authority Revenue Bonds Due 2011		5.0			-
Kinder Morgan Columbus LLC
5.50% Mississippi Business Finance Corporation Revenue Bonds Due 2022		8.2			-
Unamortized Debt Discount on Long-term Debt		(14.5	)		(6.4	)
Current Maturities of Long-term Debt		(293.7	)		(79.8	)
Total Long-term Debt	$	12,126.8		$	15,297.4

__________

1   Adjustment of carrying value of long-term securities subject to outstanding interest rate swaps; see Note 15.

In February 2008, approximately $4.6 billion of the proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC were used to pay off and retire our senior secured credit facility’s Tranche A and Tranche B term loans and to pay down amounts outstanding at that time under our $1.0 billion revolving credit facility as follows:

	Debt Paid Down and/or Retired
	(In millions)
Kinder Morgan, Inc.
Senior Secured Credit Term Loan Facilities
Tranche A Term Loan, Due 2013		$	995.0
Tranche B Term Loan, Due 2014			3,183.5
Credit Facility
$1.0 billion Secured Revolver, Due May 2013			375.0
Total Paid Down and/or Retired		$	4,553.5

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In March 2008, using primarily proceeds from the completed sale of an 80% ownership interest in NGPL PipeCo LLC, along with cash on hand and borrowings under our $1.0 billion revolving credit facility, we repurchased approximately $1.67 billion par value of our outstanding debt securities for $1.6 billion in cash as follows:

	Par Value of Debt Repurchased
	(In millions)
Kinder Morgan, Inc.
Debentures
6.50% Series, Due 2013		$	18.9
6.67% Series, Due 2027			143.0
7.25% Series, Due 2028			461.0
7.45% Series, Due 2098			124.1
Senior Notes
6.50% Series, Due 2012			160.7
Kinder Morgan Finance Company, LLC
6.40% Series, Due 2036			513.6
Deferrable Interest Debentures Issued to Subsidiary Trusts
8.56% Junior Subordinated Deferrable Interest Debentures Due 2027			87.3
7.63% Junior Subordinated Deferrable Interest Debentures Due 2028			160.6
Repurchase of Outstanding Debt Securities		$	1,669.2

As of December 31, 2008, maturities of long-term debt (in millions) for the five years ending December 31, 2013 and thereafter were $293.7, $271.9, $1,471.2, $2,305.7, $506.5 and $6,647.0, respectively.

Kinder Morgan, Inc.

The 2013 Debentures are not redeemable prior to maturity. The 2028 and 2098 Debentures and the 2012 senior notes are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. The 2015 senior notes are redeemable in whole or in part at our option, but at redemption prices that generally do not make early redemption an economically favorable alternative. The 2027 Debentures are redeemable in whole or in part, at our option after November 1, 2004 at redemption prices defined in the associated prospectus supplements.

On September 5, 2008 and September 3, 2007, we made a $5.0 million payment on each date on our 6.50% Series Debentures, Due 2013.

On May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at 101.39% of the face amount. We paid a premium of $4.2 million in connection with this early extinguishment of debt.

Kinder Morgan Finance Company, LLC

The 2011, 2016 and 2036 senior notes issued by Kinder Morgan Finance Company, LLC are redeemable in whole or in part, at our option at any time, at redemption prices defined in the associated prospectus supplements. Each series of these notes is fully and unconditionally guaranteed by Kinder Morgan, Inc. on a senior unsecured basis as to principal, interest and any additional amounts required to be paid as a result of any withholding or deduction for Canadian taxes. Additionally, the 6.40% senior notes due 2016 had an associated fixed-to-floating interest rate swap agreement with a notional principal amount of $275 million, which was terminated in 2008. See Note 15 for additional information on this swap agreement.

Kinder Morgan Energy Partners

Kinder Morgan Energy Partners’ fixed rate notes provide for redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. Approximately $2.3 billion of Kinder Morgan Energy Partners’ senior notes have associated fixed-to-floating interest rate swap agreements that effectively convert the related interest expense from fixed rates to floating rates. See Note 15 for additional information on these swap agreements.

On December 19, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing a total of $500 million in principal amount of 9.00% senior notes due February 1, 2019. Kinder Morgan Energy Partners used the $498.4 million net proceeds, after underwriting discounts and commissions, to reduce the borrowings under its revolving credit facility.

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On June 6, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing $700 million in principal amount of senior notes, consisting of $375 million of 5.95% notes due February 15, 2018 (these notes constitute a further issuance of the $600 million aggregate principal amount of 5.95% notes Kinder Morgan Energy Partners issued on February 12, 2008 and form a single series with those notes) and $325 million of 6.95% notes due January 15, 2038 (these notes constitute a further issuance of the combined $850 million aggregate principal amount of 6.95% notes Kinder Morgan Energy Partners issued on June 21, 2007 and February 12, 2008, and form a single series with those notes). Kinder Morgan Energy Partners used the $687.7 million net proceeds, after underwriting discounts and commissions, to reduce the borrowings under its commercial paper program.

On February 12, 2008, Kinder Morgan Energy Partners completed a public offering of senior notes, issuing a total of $900 million in principal amount of senior notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300 million of 6.95% notes due January 15, 2038 (the 6.95% notes constitute a further issuance of the $550 million aggregate principal amount of 6.95% notes Kinder Morgan Energy Partners issued on June 21, 2007 and form a single series with those notes). Kinder Morgan Energy Partners used the $894.1 million net proceeds to reduce borrowings under its commercial paper program.

On August 28, 2007, Kinder Morgan Energy Partners issued $500 million of its 5.85% senior notes due September 15, 2012. Kinder Morgan Energy Partners used the $497.8 million net proceeds received after underwriting discounts and commissions to reduce the borrowings under its commercial paper program.

On August 15, 2007, Kinder Morgan Energy Partners repaid $250 million of its 5.35% senior notes that matured on that date.

On June 21, 2007, Kinder Morgan Energy Partners issued $550 million of its 6.95% senior notes due January 15, 2038. Kinder Morgan Energy Partners used the $543.9 million net proceeds received after underwriting discounts and commissions to reduce the borrowings under its commercial paper program.

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

Central Florida Pipeline LLC Debt

Central Florida Pipeline LLC was an obligor on an aggregate principal amount of $40 million of senior notes originally issued to a syndicate of eight insurance companies. The senior notes had a fixed annual interest rate of 7.84% with repayments in annual installments of $5.0 million beginning July 23, 2001. Central Florida Pipeline LLC paid the final $5.0 million outstanding principal amount on July 23, 2008.

Arrow Terminals L.P. Debt

Arrow Terminals L.P. is an obligor on Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois Development Finance Authority. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed quarterly at the Bond Market Association Municipal Swap Index. The bonds are collateralized by a first mortgage on assets of Arrow’s Chicago operations and a third mortgage on assets of Arrow’s Pennsylvania operations. As of December 31, 2008, the interest rate was 1.328%. A $5.4 million letter of credit issued by JP Morgan Chase backs-up the $5.3 million principal amount of the bonds and $0.1 million of interest on the bonds for up to 45 days computed at 12% per annum on the principal amount thereof.

Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company Debt

Effective January 1, 2007, Kinder Morgan Energy Partners acquired the remaining approximate 50.2% interest in the Cochin pipeline system that it did not already own (see Note 10). As part of Kinder Morgan Energy Partners’ purchase price, two of its subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million. Kinder Morgan Energy Partners 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. Kinder Morgan Energy Partners paid the first installment on March 31, 2008 and the final payment is due March 31, 2012. Kinder Morgan Energy Partners’ subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company, are the obligors on the note.

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Kinder Morgan Texas Pipeline, L.P. Debt

Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes with a fixed annual stated interest rate of 8.85%. The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million. The final payment is due January 2, 2014.

Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid.

Kinder Morgan Liquids Terminals LLC Debt

Kinder Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. These bonds have a maturity date of January 15, 2018. These bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2008, the annual interest rate was 0.52%. Kinder Morgan Energy Partners has an outstanding letter of credit issued by Citibank in the amount of $25.4 million that backs-up the $25.0 million principal amount of the bonds and $0.4 million of interest on the bonds for up to 46 days computed at 12% on a per annum basis on the principal thereof.

Kinder Morgan Operating L.P. “B” Debt

As of December 31, 2008, Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “B” was the obligor of tax-exempt bonds due April 1, 2024. The bonds were issued by the Jackson-Union Counties Regional Port District, a political subdivision embracing the territories of Jackson County and Union County in the state of Illinois. These variable rate demand bonds bear interest at a weekly floating market rate and are backed-up by a letter of credit issued by Wachovia.

The bond indenture also contains certain standby purchase agreement provisions, which allow investors to put (sell) back their bonds at par plus accrued interest. In the fourth quarter of 2008, certain investors elected to sell back their bonds and Kinder Morgan Energy Partners paid a total principal and interest amount of $5.2 million according to the letter of credit reimbursement provisions. However, the bonds were subsequently resold and as of December 31, 2008, Kinder Morgan Energy Partners was fully reimbursed for the prior payments. As of December 31, 2008, the annual interest rate on these bonds was 3.04%. Kinder Morgan Energy Partners has an outstanding letter of credit issued by Wachovia in the amount of $18.0 million that backs-up the principal amount of $17.7 million the bonds and $0.3 million of interest on the bonds for up to 55 days computed at 12% per annum on the principal amount thereof.

International Marine Terminals Debt

Kinder Morgan Energy Partners owns a 66 2/3% interest in International Marine Terminals partnership (“IMT”). The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. As of December 31, 2008, the annual interest rate on these bonds was 2.20%.

On March 15, 2005, these bonds were refunded and the maturity date was extended from March 15, 2006 to March 15, 2025. No other changes were made under the bond provisions. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, Kinder Morgan Energy Partners agreed to guarantee the obligations of IMT in proportion to its ownership interest. Kinder Morgan Energy Partners’ obligation is approximately $30.3 million for principal, plus interest and other fees.

Gulf Opportunity Zone Bonds

To help fund business growth in the states of Mississippi and Louisiana, Kinder Morgan Energy Partners completed the purchase of a combined $13.2 million in principal amount of tax exempt revenue bonds in two separate transactions in December 2008. The bond offerings were issued under the Gulf Opportunity Zone Act of 2005 and consisted of the following: (i) $8.2 million in principal amount of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance Corporation, a public, non-profit corporation that coordinates a variety of resources used to assist business and industry in the state of Mississippi and (ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued by the Louisiana Community Development Authority, a political subdivision of the state of Louisiana.

The Mississippi revenue bonds mature on September 1, 2022, and both principal and interest are due in full at maturity. Kinder Morgan Energy Partners holds an option to redeem the bonds in full (and settle the note payable to the Mississippi

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Business Finance Corporation) without penalty after one year. The Louisiana revenue bonds have a maturity date of January 1, 2011 and provide for semi-annual interest payments each July 1 and January 1.

Capital Trust Securities

Our business trusts, K N Capital Trust I and K N Capital Trust III, are obligated for $15.8 million of 8.56% Capital Trust Securities maturing on April 15, 2027 and $19.9 million of 7.63% Capital Trust Securities maturing on April 15, 2028, respectively, which are guaranteed by us. The 2028 Securities are redeemable in whole or in part, at our option at any time, at redemption prices as defined in the associated prospectus. The 2027 Securities are redeemable in whole or in part at our option and at any time in certain limited circumstances upon the occurrence of certain events and at prices, all defined in the associated prospectus supplements. Upon redemption by us or at maturity of the Junior Subordinated Deferrable Interest Debentures, we must use the proceeds to make redemptions of the Capital Trust Securities on a pro rata basis.

Common Stock – Financing of the Going Private Transaction

On May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief Executive Officer, completed the Going Private transaction. As of the closing date of the Going Private transaction, Kinder Morgan, Inc. had 149,316,603 common shares outstanding, before deducting 15,030,135 shares held in treasury. The Going Private transaction, including associated fees and expenses, was financed through (i) $5.0 billion in new equity financing from private equity funds and other entities providing equity financing, (ii) approximately $2.9 billion from rollover investors, who were certain current or former directors, officers or other members of management of Kinder Morgan, Inc. (or entities controlled by such persons) that directly or indirectly reinvested all or a portion of their equity interests in Kinder Morgan, Inc. and/or cash in exchange for equity interests in Kinder Morgan Holdco LLC, the parent of the surviving entity of the Going Private transaction, (iii) approximately $4.8 billion of new debt financing, (iv) approximately $4.5 billion of our existing indebtedness (excluding debt of Terasen Pipelines (Corridor) Inc., which was divested on June 15, 2007) and (v) $1.7 billion of cash on hand resulting principally from the sale of our U.S.-based and Canada-based retail natural gas distribution operations (see Note 1).

Kinder Morgan Energy Partners’ Common Units

On December 22, 2008, Kinder Morgan Energy Partners issued, in a public offering, 3,900,000 of Kinder Morgan Energy Partners’ common units at a price of $46.75 per unit, less commissions and underwriting expenses. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $176.6 million for the issuance of these common units, and used the proceeds to reduce the borrowings under its bank credit facility. This transaction had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $170.6 million and (ii) associated accumulated deferred income taxes by $2.2 million and reducing our (i) goodwill by $7.6 million and (ii) paid-in capital by $3.8 million.

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

In connection with the August 28, 2008 sale of our one-third ownership interest in the Express pipeline system and the full interest in the net assets of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of its common units to us. These units, as agreed by Kinder Morgan Energy Partners and us, were valued at $116.0 million. For more information on this acquisition, see Note 10.

On March 3, 2008, Kinder Morgan Energy Partners issued, in a public offering, 5,000,000 of its common units at a price of $57.70 per unit, less commissions and underwriting expenses. At the time of the offering, Kinder Morgan Energy Partners granted the underwriters a 30-day option to purchase up to an additional 750,000 of its common units on the same terms and conditions, and pursuant to this option, Kinder Morgan Energy Partners issued an additional 750,000 common units on March 10, 2008 upon exercise of this option. After commissions and underwriting expenses, Kinder Morgan Energy Partners received net proceeds of $324.2 million for the issuance of these 5,750,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $311.2 million and (ii) associated accumulated

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deferred income taxes by $4.7 million and reducing our (i) goodwill by $21.6 million and (ii) paid-in capital by $13.3 million.

On February 12, 2008, Kinder Morgan Energy Partners completed an offering of 1,080,000 of its common units at a price of $55.65 per unit in a privately negotiated transaction. Kinder Morgan Energy Partners received net proceeds of $60.1 million for the issuance of these 1,080,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $57.6 million and (ii) associated accumulated deferred income taxes by $0.9 million and reducing our (i) goodwill by $4.2 million and (ii) paid-in capital by $2.6 million.

On December 5, 2007, Kinder Morgan Energy Partners issued, in a public offering, 7,130,000 of its common units, including common units sold pursuant to the underwriters’ over-allotment option, at a price of $48.09 per common unit, less underwriting expenses, receiving total net proceeds of $342.9 million. This transaction had the associated effects of increasing our noncontrolling interests associated with Kinder Morgan Energy Partners by $330.1 million and reducing our (i) goodwill by $33.8 million, (ii) associated accumulated deferred income taxes by $7.6 million and (iii) paid-in capital by $13.4 million.

In December 2006, Kinder Morgan Energy Partners issued 34,627 common units as partial consideration for the acquisition of Devco USA L.L.C. This transaction had the associated effects of increasing our noncontrolling interests associated with Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by $110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii) paid-in capital by $18,589.

In August 2006, Kinder Morgan Energy Partners issued, in a public offering, 5,750,000 common units, including common units sold pursuant to an underwriters’ over-allotment option, at a price of $44.80 per unit, less commissions and underwriting expenses. Kinder Morgan Energy Partners received net proceeds of approximately $248.0 million for the issuance of these 5,750,000 common units, and used the proceeds to reduce the borrowings under its commercial paper program. This transaction had the associated effects of increasing our noncontrolling interests associated with Kinder Morgan Energy Partners by $236.8 million and reducing our (i) goodwill by $18.8 million, (ii) associated accumulated deferred income taxes by $2.8 million and (iii) paid-in capital by $4.7 million.

Kinder Morgan G.P., Inc. Preferred Shares

On July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057 to a single purchaser. We used the net proceeds of approximately $98.6 million after the initial purchaser’s discounts and commissions to reduce debt. Until August 18, 2012, dividends will accumulate, commencing on the issue date, at a fixed rate of 8.33% per annum and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2007. After August 18, 2012, dividends on the preferred stock will accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and will be payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by Kinder Morgan Energy Partners or its SFPP, L.P. or Calnev Pipe Line LLC subsidiaries.

During 2008, $8.3 million in cash dividends, or $83.3 per share, was paid on our Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock. On January 21, 2009, Kinder Morgan G.P., Inc.’s board of directors declared a quarterly cash dividend on its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock of $20.825 per share payable on February 18, 2009 to shareholders of record as of January 30, 2009.

Kinder Morgan Management

On May 15, 2007, Kinder Morgan Management sold 5.7 million listed shares in a registered offering at a price of $52.26 per share. None of the shares in the offering were purchased by us. Kinder Morgan Management used the net proceeds from the sale to purchase 5.7 million i-units from Kinder Morgan Energy Partners. Kinder Morgan Energy Partners used the net proceeds of approximately $297.9 million to reduce its outstanding commercial paper debt. This transaction had the associated effects of increasing our (i) noncontrolling interests associated with Kinder Morgan Energy Partners by $22.7 million, (ii) associated accumulated deferred income taxes by $1.9 million and (iii) paid-in capital by $3.4 million, and reducing our goodwill by $17.4 million. Additional information concerning the business of, and our obligations to, Kinder Morgan Management is contained in Kinder Morgan Management’s Annual Report on Form 10-K for the year ended December 31, 2008.

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Credit Ratings

	Standard & Poor’s	Moody’s	Fitch
Kinder Morgan, Inc.
$1.0 billion, six-year secured revolver, due May 2013	BB	Ba1	BB+
Kinder Morgan Energy Partners
$1.85 billion, five-year unsecured revolver, due August 2010	BBB	Baa2	BBB

A securities rating is not a recommendation to buy, sell or hold a security, may be subject to revision or withdrawal at any time by the issuing ratings agency in its sole discretion and should be evaluated independently of any other rating.

In conjunction with the Going Private transaction, Kinder Morgan, Inc. incurred approximately $4.8 billion in additional debt. Standard & Poor’s Rating Services (“Standard & Poor’s”) and Moody’s Investors Service (“Moody’s”) downgraded the ratings assigned to Kinder Morgan, Inc.’s senior unsecured debt to BB-and Ba2, respectively. Upon the February 2008 80% ownership interest sale of our NGPL business segment, which resulted in Kinder Morgan, Inc.’s repayment of a substantial amount of debt, Standard & Poor’s and Fitch’s upgraded Kinder Morgan, Inc.’s senior unsecured debt to BB and BB+, respectively. However, these ratings are still below investment grade. Since the Going Private transaction, Kinder Morgan, Inc. has not had access to the commercial paper market and is currently utilizing its $1.0 billion revolving credit facility for its short-term borrowing needs.

On October 13, 2008, Standard & Poor’s revised its outlook on Kinder Morgan Energy Partners’ long-term credit rating to negative from stable (but affirmed Kinder Morgan Energy Partners’ long-term credit rating at BBB), due to Kinder Morgan Energy Partners’ previously announced expected delay and cost increases associated with the completion of the Rockies Express Pipeline project. At the same time, Standard & Poor’s lowered Kinder Morgan Energy Partners’ short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Kinder Morgan Energy Partners is unable to access commercial paper borrowings. However, Kinder Morgan Energy Partners expects that short-term financing and liquidity needs will continue to be met through borrowings made under its bank credit facility.

Fair Value of Financial Instruments

Fair value as used in SFAS No. 107, “Disclosures About Fair Value of Financial Instruments,” represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair value of our long-term debt, including its current portion, is based upon prevailing interest rates available to us as of December 31, 2008 and December 31, 2007 and is disclosed below (in millions).

	December 31, 2008				December 31, 2007
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Total Debt	$	12,420.5	$	10,776.1	$	15,377.2	$	15,093.7

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

Interest Expense, Net

Total “Interest Expense, Net” as presented in the accompanying Consolidated Statements of Operations is comprised of the following.

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Interest Expense, Net	$	674.3		$	603.4		$	253.3		$	576.1
Capitalized Interest1		(49.3	)		(25.5	)		(12.2	)		(23.3	)
Interest Expense – Preferred Interest in General Partner of KMP		8.4			3.6			-			-
Total Interest Expense, Net	$	633.4		$	581.5		$	241.1		$	552.8

__________

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1 Includes the debt component of the allowance for funds used during construction for our regulated utility operations, which are accounted for in accordance with the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

“Interest Expense–Net” as presented in the accompanying Consolidated Statement of Operations includes gains and losses from (i) the reacquisition of debt, (ii) the termination of interest rate swaps designated as fair value hedges for which the hedged liability has been extinguished and (iii) the termination of interest rate swaps designated as cash flow hedges for which the forecasted interest payments will no longer occur. During the year ended December 31, 2008, we recorded a $34.4 million loss from the early extinguishment of debt in the caption “Interest Expense, Net,” consisting of an $18.1 million gain on the debt repurchased in the tender more than offset by a $41.7 million loss from the write-off of debt issuance costs associated with the $5.755 billion secured credit facility. We also recorded $19.8 million of gains from the termination of interest rate swaps designated as fair value hedges, for which the hedged liability was extinguished, in the caption “Interest Expense, Net” in the accompanying Consolidated Statements of Operations.

“Interest Expense-Net” for the seven months ended December 31, 2007 includes approximately $179.6 million of interest expense related to the increased debt incurred in the Going Private transaction (See Note 1) and $236.4 million related to Kinder Morgan Energy Partners. “Interest Expense – Net” for the five months ended May 31, 2007 includes $155.0 million related to Kinder Morgan Energy Partners. Included in “Interest Expense-Net” in 2006 is $332.0 million of interest expense relating to Kinder Morgan Energy Partners and $61.3 million of interest expense related to Terasen.

15. Risk Management

We are exposed to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil as a result of our expected future purchase or sale of these products. We have exposure to interest rate risk as a result of the issuance of variable and fixed rate debt and to foreign currency risk from our investments in businesses owned and operated outside the United States. Pursuant to our risk management policy, we engage in derivative transactions for the purpose of mitigating these risks, which transactions are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and associated amendments (“SFAS No. 133”).

Commodity Price Risk Management

Our principal use of energy commodity derivative contracts is to mitigate the risk associated with market fluctuations in the price of energy commodities. In accordance with the provisions of SFAS No. 133, we designate these instruments as hedges of various exposures as discussed following, and we test the effectiveness of changes in the value of these hedging instruments with the risk being hedged. Hedge ineffectiveness is recognized in income in the period in which it occurs. Our over-the-counter swaps and options are entered into with counterparties outside central trading facilities such as a futures, options or stock exchange. These contracts are with a number of parties all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk.

Our normal business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil. Reflecting the portion of changes in the value of derivative contracts that were not effective in offsetting changes in expected cash flows (the ineffective portion of hedges) and to the extent of our economic ownership, we recognized a pre-tax loss of $1.5 million during the year ended December 31, 2008. We recognized a pre-tax gain of approximately $0.5 million and a pre-tax loss of approximately $0.7 million in the seven months ended December 31, 2007 and five months ended May 31, 2007, respectively, and a pre-tax gain of approximately $5.9 million for the year ended December 31, 2006. The gains and losses for each respective period were a result of ineffectiveness of these hedges, which amounts are reported within the captions “Natural Gas Sales,” “Product Sales and Other,” “Gas Purchases and Other Costs of Sales,” “Earnings of Equity Investees” and “Noncontrolling Interests” in the accompanying Consolidated Statements of Operations, and for each of the respective periods, we did not exclude any component of the derivative contracts’ gain or loss from the assessment of hedge effectiveness.

As the hedged sales and purchases take place and we record them into earnings, we also reclassify the associated gains and losses included in accumulated other comprehensive income into earnings. During the year ended December 31, 2008, the seven months ended December 31, 2007, the five months ended May 31, 2007 and the year ended December 31, 2006, we reclassified $418.2 million, $137.2 million, $66.8 million and $352.5 million, respectively, of accumulated other comprehensive loss into earnings, as a result of hedged forecasted transactions occurring during these periods. Furthermore, during the five months ended May 31, 2007 and year ended December 31, 2006, we reclassified $1.1 million of net gains and $2.9 million of net losses, respectively, into earnings as a result of 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 year ended December 31, 2008 and the seven months ended December 31, 2007, we did not reclassify any of our accumulated other comprehensive loss into earnings as a result of the discontinuance of cash flow hedges due to a determination that forecasted transactions would no longer occur by the end of the originally specified time period. During

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the next twelve months, we expect to reclassify approximately $59.0 million of accumulated other comprehensive income into earnings.

Effective at the beginning of the second quarter of 2008, Kinder Morgan Energy Partners determined that the derivative contracts of its Casper and Douglas natural gas processing operations that previously had been designated as cash flow hedges for accounting purposes no longer met the hedge effectiveness assessment as required by SFAS No. 133. Consequently, we discontinued hedge accounting treatment for these relationships (primarily crude oil hedges of heavy natural gas liquids sales) effective as of March 31, 2008. Since the forecasted sales of natural gas liquids volumes (the hedged item) are still expected to occur, all of the accumulated losses through March 31, 2008 on the related derivative contracts remained in accumulated other comprehensive income, and will not be reclassified into earnings until the physical transactions occurs. Any changes in the value of the these derivative contracts subsequent to March 31, 2008 will no longer be deferred in other comprehensive income, but rather will impact current period income. As a result, we recognized an increase in income of $5.6 million in 2008 related to the increase in value of derivative contracts outstanding as of December 31, 2008 for which hedge accounting had been discontinued.

Derivative instruments that are entered into for the purpose of mitigating commodity price risk include swaps, futures and options. Additionally, basis swaps may also be used in connection with another derivative contract to reduce hedge ineffectiveness by reducing basis difference between hedged exposure and a derivative contract. The fair values of these derivative contracts reflect the amounts that we would receive or pay to terminate the contracts at the reporting date and are included in the accompanying Consolidated Balance Sheets as of December 31, 2008 and 2007 within the captions indicated in the following table:

	December 31, 2008			December 31, 2007
	(In millions)
Derivatives Asset (Liability)
Current Assets: Fair Value of Derivative Instruments	$	115.3		$	37.1
Current Assets: Assets Held for Sale	$	-		$	8.4
Assets: Fair Value of Derivative Instruments, Non-current	$	48.9		$	4.4
Current Liabilities: Fair Value of Derivative Instruments	$	(129.5	)	$	(594.7	)
Current Liabilities: Liabilities Held for Sale	$	-		$	(0.4	)
Liabilities and Stockholders’ Equity: Fair Value of Derivative Instruments, Non-current	$	(92.2	)	$	(836.8	)

Interest Rate Risk Management

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.

Prior to the Going Private transaction, all of our interest rate swaps qualified for, and since the Going Private transaction, the new interest rate swaps that Kinder Morgan Energy Partners entered into in February 2008, discussed below, qualify for the “short-cut” method prescribed in SFAS No. 133 for qualifying fair value hedges. Under this method, the carrying value of the swap is adjusted to its fair value as of the end of each reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. Interest expense is equal to the floating rate payments, which is accrued monthly and paid semi-annually.

In connection with the Going Private transaction, all of our debt, including debt of our subsidiary, Kinder Morgan Energy Partners, was remeasured and recorded on our balance sheet at fair value to the extent of our economic ownership interest. Except for Corridor’s outstanding interest rate swap agreements classified as held for sale, all of our interest rate swaps and swaps of our subsidiary, Kinder Morgan Energy Partners, were re-designated as fair value hedges effective June 1, 2007. Because these swaps did not have a fair value of zero as of June 1, 2007, they did not meet the requirements for the “short-cut” method of assessing their effectiveness. Accordingly, the carrying value of the swap is adjusted to its fair value as of the end of each subsequent reporting period, and an offsetting entry is made to adjust the carrying value of the debt securities whose fair value is being hedged. Any hedge ineffectiveness resulting from the difference between the change in fair value of the interest rate swap and the change in fair value of the hedged debt instrument is recorded as interest expense in the current period. During the year ended December 31, 2008, no hedge ineffectiveness related to these hedges was recognized. Interest expense equal to the floating rate payments is accrued monthly and paid semi-annually.

As of December 31, 2007, we, and our subsidiary Kinder Morgan Energy Partners, were parties to interest rate swap agreements with notional principal amounts of $275 million and $2.3 billion, respectively, for a consolidated total of $2.575 billion. On March 7, 2008, we paid $2.5 million to terminate our remaining interest rate swap agreement having a notional

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value of $275 million associated with Kinder Morgan Finance Company, LLC’s 6.40% senior notes due 2036. In February 2008, Kinder Morgan Energy Partners entered into two additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $500 million related to its $600 million 5.95% senior notes issued on February 12, 2008. Additionally, on June 6, 2008, following Kinder Morgan Energy Partner’s issuance of $700 million in principal amount of senior notes in two separate series, Kinder Morgan Energy Partners entered into two additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $700 million. In December 2008, Kinder Morgan Energy Partners took advantage of the general decrease in variable interest rates since the start of 2008 by terminating two of its existing agreements in separate transactions having (i) a notional principal amount of $375 million and a maturity date of February 15, 2018; and (ii) a notional principal amount of $325 million and a maturity date of January 15, 2038, in which it received combined proceeds of $194.3 million from the early termination of these swap agreements. Therefore, as of December 31, 2008, we were not party to any interest rate swap agreements and Kinder Morgan Energy Partners was a party to fixed-to-floating interest rate swap agreements with a combined notional principal amount of $2.8 billion; effectively converting the interest expense associated with certain series of its senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.

The fair value of interest rate swaps at December 31, 2008 and 2007 of $747.1 million and $139.1 million, respectively, are included in the accompanying Consolidated Balance Sheets within the captions “Assets: Fair Value of Derivative Instruments, Non-current.” The total unamortized net gain on the termination of interest rate swaps of $216.8 million is included within the caption “Long-term Debt: Value of Interest Rate Swaps” in the accompanying Consolidated Balance Sheet at December 31, 2008. All of Kinder Morgan Energy Partners’ swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of December 31, 2008, the maximum length of time over which Kinder Morgan Energy Partners has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through January 15, 2038.

Net Investment Hedges

We are exposed to foreign currency risk from our investments in businesses owned and operated outside the United States. To hedge the value of our investment in Canadian operations, we have entered into various cross-currency interest rate swap transactions that have been designated as net investment hedges in accordance with SFAS No. 133. We have recognized no ineffectiveness through the income statement as a result of these hedging relationships during the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007, or year ended December 31, 2006. The effective portion of the changes in fair value of these swap transactions is reported as a cumulative translation adjustment under the caption “Accumulated Other Comprehensive Loss” in the accompanying Consolidated Balance Sheets at December 31, 2008 and 2007.

The notional value of our remaining cross-currency interest rate swaps at December 31, 2008 and 2007 was approximately C$154.7 and C$281.6 million, respectively. The fair value of the swaps as of December 31, 2008 was an asset of $32.0 million and at December 31, 2007 was a liability of $51.2 million, which amounts are included in the caption “Assets: Fair Value of Derivative Instruments, Non-current” and “Liabilities and Stockholders’ Equity: Fair Value of Derivative Instruments, Non-current” in the accompanying Consolidated Balance Sheets, respectively. In October 2008, we received $150,000 for the termination of cross-currency interest rate swaps with a combined notional amount of C$126.9 million.

SFAS No. 157

On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. In general, fair value measurements and disclosures are made in accordance with the provisions of this Statement and, while not requiring material new fair value measurements, SFAS No. 157 established a single definition of fair value in GAAP and expanded disclosures about fair value measurements. The provisions of this Statement apply to other accounting pronouncements that require or permit fair value measurements; the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute.

On February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FAS 157-2”). FAS 157-2 delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Accordingly, we adopted SFAS No. 157 for financial assets and financial liabilities effective January 1, 2008. The adoption did not have a material impact on our balance sheet, statement of operations, or statement of cash flows since we already apply its basic concepts in measuring fair values.

We adopted SFAS No. 157 for non-financial assets and non-financial liabilities effective January 1, 2009. This includes applying the provisions of SFAS No. 157 to (i) nonfinancial assets and liabilities initially measured at fair value in business combinations; (ii) reporting units or nonfinancial assets and liabilities measured at fair value in conjunction with goodwill impairment testing; (iii) other nonfinancial assets measured at fair value in conjunction with impairment assessments; and (iv) asset retirement obligations initially measured at fair value. The adoption did not have a material impact on our balance

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sheet, statement of operations, or statement of cash flows since we already apply its basic concepts in measuring fair values.

On October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, (“FAS 157-3). FAS 157-3 provides clarification regarding the application of SFAS No. 157 in inactive markets. The provisions of FAS 157-3 are effective immediately. This Staff Position did not have any material effect on our consolidated financial statements.

The degree of judgment utilized in measuring the fair value of financial instruments generally correlates to the level of pricing observability. Pricing observability is affected by a number of factors, including the type of financial instrument, whether the financial instrument is new to the market, and the characteristics specific to the transaction. Financial instruments with readily available active quoted prices or for which fair value can be measured from actively quoted prices generally will have a higher degree of pricing observability and a lesser degree of judgment utilized in measuring fair value. Conversely, financial instruments rarely traded or not quoted will generally have less (or no) pricing observability and a higher degree of judgment utilized in measuring fair value.

SFAS No. 157 established a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process, and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the SFAS No. 157 hierarchy are as follows:

· Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

· Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

· Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).

Derivative contracts can be exchange-traded or over-the-counter, referred to in this report as OTC. Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We and Kinder Morgan Energy Partners value exchange-traded derivative contracts using quoted market prices for identical securities.

OTC derivative contracts are valued using models utilizing a variety of inputs including contractual terms, commodity, interest rate and foreign currency curves, and measures of volatility. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We and Kinder Morgan Energy Partners use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information, and the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivative contracts are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements.

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. Our fair value measurements of derivative contracts are adjusted for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the net asset balance associated with these contracts recorded in the accompanying Consolidated Balance Sheet includes a reduction of $2.2 million related to discounting the value of our energy commodity derivative liabilities for the effect of credit risk. We also adjusted the fair value measurements of our interest rate swap agreements for credit risk in accordance with SFAS No. 157, and as of December 31, 2008, the value of interest rate swaps included a decrease (loss) of $10.6 million related to discounting the fair value measurement of our interest rate swap agreements’ asset value for the effect of credit risk.

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The following tables summarize the fair value measurements of our (i) energy commodity derivative contracts, (ii) interest rate swap agreements and (iii) cross-currency interest rate swaps as of December 31, 2008, based on the three levels established by SFAS No. 157, and does not include cash margin deposits, which are reported in the caption “Current Assets: Restricted Deposits” in the accompanying Consolidated Balance Sheet.

	Asset Fair Value Measurements as of December 31, 2008 Using
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Energy Commodity Derivative Contracts1	$	164.2	$	0.1	$	108.9	$	55.2
Interest Rate Swap Agreements	$	747.1	$	-	$	747.1	$	-
Cross-currency Interest Rate Swaps	$	32.0	$	-	$	32.0	$	-

	Liability Fair Value Measurements as of December 31, 2008 Using
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(In millions)
Energy Commodity Derivative Contracts2	$	(221.7	)	$	-	$	(210.6	)	$	(11.1	)
Interest Rate Swap Agreements	$	-		$	-	$	-		$	-

____________

1 Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on the New York Mercantile Exchange (“NYMEX”). Level 3 consists primarily of West Texas Intermediate options and West Texas Sour hedges.

2 Level 2 consists primarily of OTC West Texas Intermediate hedges. Level 3 consists primarily of natural gas basis swaps, natural gas options and West Texas Intermediate options.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for the year ended December 31, 2008:

Significant Unobservable Inputs (Level 3)

	Year Ended December 31, 2008
	(In millions)
Net Asset (Liability)
Beginning Balance	$	(100.3	)
Realized and Unrealized Net Losses		69.6
Purchases and Settlements		74.8
Balance as of December 31, 2008	$	44.1
Change in Unrealized Net Losses Relating to Contracts Still Held as of December 31, 2008	$	88.8

Credit Risks

We and Kinder Morgan Energy Partners have counterparty credit risk as a result of our use of energy commodity derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative

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exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.

Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as a futures, options or stock exchange. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.

In addition, in conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2008 and December 31, 2007, Kinder Morgan Energy Partners had outstanding letters of credit totaling $40.0 million and $298.0 million, respectively, in support of its hedging of commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. Additionally, as of December 31, 2008, Kinder Morgan Energy Partners’ counterparties associated with its energy commodity contract positions and over-the-counter swap agreements had margin deposits with Kinder Morgan Energy Partners totaling $3.1 million, and we reported this amount in the caption “Other” within “Current Liabilities” in the accompanying Consolidated Balance Sheet. As of December 31, 2007, we had cash margin deposits associated with Kinder Morgan Energy Partners’ commodity contract positions and over-the-counter swap partners totaling $67.9 million, and we reported this amount in the caption “Current Assets: Restricted Deposits” in the accompanying Consolidated Balance Sheet.

We and Kinder Morgan Energy Partners are also exposed to credit related losses in the event of nonperformance by counterparties to our interest rate swap agreements, and while we and Kinder Morgan Energy Partners enter into these agreements 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 in the future. As of December 31, 2008, all of our and Kinder Morgan Energy Partners’ interest rate swap agreements were with counterparties with investment grade credit ratings, and the $747.1 million total fair value of our and Kinder Morgan Energy Partners’ interest rate swap derivative assets at December 31, 2008 (disclosed above) included amounts of $301.8 million and $249.0 million related to open positions with Citigroup and Merrill Lynch, respectively.

16. Employee Benefits

Kinder Morgan, Inc.

Retirement Plans

We have defined benefit pension plans covering eligible full-time employees. These plans provide pension benefits that are based on the employees’ compensation during the period of employment, age and years of service. These plans are tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended. Our funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds. The Plan did not have any material investments in our company or affiliates as of December 31, 2008 and 2007.

Total amounts recognized in net periodic pension cost include the following components:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Net Periodic Pension Benefit Cost
Service Cost	$	10.8		$	5.6		$	4.5		$	10.6
Interest Cost		14.5			8.1			5.6			12.7
Expected Return on Assets		(23.2	)		(14.0	)		(9.6	)		(21.3	)
Amortization of Prior Service Cost		0.1			-			0.1			0.2
Amortization of Loss		0.3			-			0.2			0.9
Net Periodic Pension Benefit Cost	$	2.5		$	(0.3	)	$	0.8		$	3.1

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The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007
	(In millions)						(In millions)
Benefit Obligation at Beginning of Period	$	258.0		$	236.5		$	232.0
Service Cost		10.8			5.6			4.5
Interest Cost		14.5			8.1			5.6
Actuarial Loss (Gain)		(14.2	)		18.5			(2.5	)
Plan Amendments		0.8			-			2.7
Benefits Paid		(14.9	)		(10.7	)		(5.8	)
Benefit Obligation at End of Period	$	255.0		$	258.0		$	236.5

The accumulated benefit obligation at December 31, 2008 and 2007 was $248.6 million and $248.1 million, respectively.

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of the plans’ assets and the plans’ funded status:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007
	(In millions)						(In millions)
Fair Value of Plan Assets at Beginning of Period	$	264.7		$	273.4		$	261.6
Actual Return on Plan Assets During the Period		(70.1	)		1.9			17.6
Benefits Paid During the Period		(14.9	)		(10.7	)		(5.8	)
Fair Value of Plan Assets at End of Period		179.7			264.6			273.4
Benefit Obligation at End of Period		(255.0	)		(258.0	)		(236.5	)
Funded Status at End of Period	$	(75.3	)	$	6.6		$	36.9

The accompanying Consolidated Balance Sheets at December 31, 2008 include a balance of $75.3 million under the caption “Other Long-term Liabilities and Deferred Credits” related to our pension plans. At December 31, 2007, the accompanying Consolidated Balance Sheets include a balance of $7.0 million under the caption “Deferred Charges and Other Assets,” and a balance of $0.4 million under the caption “Other Long-term Liabilities and Deferred Credits” related to our pension plans.

Amounts recognized in “Accumulated Other Comprehensive Loss” consist of:

	Successor Company					Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007
	(In millions)					(In millions)
Beginning Balance	$	30.6		$	-	$	19.3
Net (Gain)/Loss Arising During Period		79.1			30.6		(10.5	)
Prior Service Cost Arising During Period		0.7			-		2.7
Amortization of (Gain)/Loss		(0.4	)		-		(0.2	)
Amortization of Prior Service Cost		(0.1	)		-		(0.1	)
Ending Balance	$	109.9		$	30.6	$	11.2

Our actuarial estimates allocate costs based on projected employee costs. As experience develops under our plan, actuarial gains (losses) result from experience more favorable (unfavorable) than assumed.

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The estimated net loss for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic pension benefit cost over the next fiscal year is $7.4 million.

We expect to contribute approximately $20 million to the Plan during 2009.

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Fiscal Year	Expected Net Benefit Payments
	(In millions)
2009	$	14.4
2010	$	15.3
2011	$	16.3
2012	$	17.1
2013	$	17.6
2014-2017	$	108.5

Effective January 1, 2001, we added a cash balance plan to our retirement plan. Certain collectively bargained employees and “grandfathered” employees continue to accrue benefits through the defined pension benefit plan described above. All other employees accrue benefits through a personal retirement account in the cash balance plan. All employees converting to the cash balance plan were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. We make contributions on behalf of these employees equal to 3% of eligible compensation every pay period. Interest is credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each year. Employees become fully vested in the plan after three years (five years prior to January 1, 2008) and they may take a lump sum distribution upon termination of employment or retirement.

In addition to our retirement plan described above, we have the Knight Inc. Savings Plan (the “Plan”), a defined contribution 401(k) plan. The plan permits all full-time employees to contribute between 1% and 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a Company contribution equal to 4% of base compensation per year for most plan participants, we may make discretionary contributions. Certain employees’ contributions are based on collective bargaining agreements. The contributions are made each pay period on behalf of each eligible employee. Participants may direct the investment of their contributions and all employer contributions, including discretionary contributions, into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. The total amount contributed for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 was $20.8 million, $11.0 million, $8.1 million and $18.3 million, respectively.

Employer contributions for employees vest on the second anniversary of the date of hire. Effective October 1, 2005, a tiered employer contribution schedule was implemented for new employees of the Terminals–KMP segment. This tiered schedule provides for employer contributions of 1% for service less than one year, 2% for service between one and two years, 3% for services between two and five years, and 4% for service of five years or more. All employer contributions for Terminals–KMP employees hired after October 1, 2005 vest on the fifth anniversary of the date of hire. Effective January 1, 2008, this five year anniversary date for Terminals –KMP employees was changed to three years to comply with changes in federal regulations. Vesting and contributions for bargaining employees will follow the collective bargaining agreements.

At its July 2008 meeting, the compensation committee of our board of directors approved a special contribution of an additional 1% of base pay into the Plan for each eligible employee. Each eligible employee will receive an additional 1% Company contribution based on eligible base pay each pay period beginning with the first pay period of August 2008 and continuing through the last pay period of July 2009. The additional 1% contribution does not change or otherwise impact, the annual 4% contribution that eligible employees currently receive and the vesting schedule mirrors the Company’s 4% contribution. Since this additional 1% Company contribution is discretionary, compensation committee approval will be required annually for each additional contribution. During the first quarter of 2009, excluding the 1% additional contribution described above, we will not make any additional discretionary contributions to individual accounts for 2008.

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

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In 2006, we elected not to make any restricted stock awards as a result of the Going Private transaction. To ensure that certain key employees who had previously received restricted stock and restricted stock unit awards continued under a long-term retention and incentive program, the Company implemented the Long-term Incentive Retention Award plan. The plan provides cash awards approved by the compensation committees of the Company which are granted in July of each year to recommended key employees. Senior management is not eligible for these awards. These grants require the employee to sign a grant agreement. The grants vest 100% after the third year anniversary of the grant provided the employee remains with the Company. Grants were made in July of 2006, 2007 and 2008. During the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, we amortized $6.9 million, $5.3 million, $1.3 million and $1.9 million, respectively, related to these grants.

Other Postretirement Employee Benefits

We have a postretirement plan providing medical and life insurance benefits upon retirement. For certain eligible employees and their eligible dependents that are “grandfathered,” we also provide a subsidized premium. All others who are eligible pay the full cost. We fund a portion of the future expected postretirement benefit cost under the plan by making payments to Voluntary Employee Benefit Association trusts. Plan assets are invested in a mix of equity funds and fixed income instruments similar to the investments in our pension plans.

Total amounts recognized in net periodic postretirement benefit cost include the following components:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
	(In millions)						(In millions)
Net Periodic Postretirement Benefit Cost
Service Cost	$	0.3		$	0.2		$	0.2		$	0.4
Interest Cost		4.6			2.7			1.9			4.9
Expected Return on Assets		(6.5	)		(3.9	)		(2.7	)		(5.8	)
Amortization of Prior Service Credit		-			-			(0.7	)		(1.6	)
Amortization of Loss		0.5			-			2.0			5.2
Net Periodic Postretirement Benefit Cost	$	(1.1	)	$	(1.0	)	$	0.7		$	3.1

The following table sets forth the reconciliation of the beginning and ending balances of the accumulated postretirement benefit obligation:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007
	(In millions)						(In millions)
Benefit Obligation at Beginning of Period	$	82.0		$	78.7		$	84.0
Service Cost		0.3			0.2			0.2
Interest Cost		4.6			2.7			1.9
Actuarial Loss (Gain)		2.0			7.5			(3.5	)
Benefits Paid		(13.8	)		(8.5	)		(5.3	)
Retiree Contributions		2.9			1.4			1.4
Benefit Obligation at End of Period	$	78.0		$	82.0		$	78.7

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The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets and the plan’s funded status:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007
	(In millions)						(In millions)
Fair Value of Plan Assets at Beginning of Period	$	69.2		$	76.9		$	67.5
Actual Return on Plan Assets		(17.5	)		0.1			4.5
Contributions		8.7			-			8.7
Retiree Contributions		2.9			1.6			1.2
Transfers In		-			0.1			-
Benefits Paid		(14.2	)		(9.5	)		(5.0	)
Fair Value of Plan Assets at End of Period		49.1			69.2			76.9
Benefit Obligation at End of Period		(78.0	)		(82.0	)		(78.7	)
Funded Status at End of Period	$	(28.9	)	$	(12.8	)	$	(1.8	)

The accompanying Consolidated Balance Sheets at December 31, 2008 and 2007 include balances of $28.9 million and $12.8 million, respectively, under the caption “Other Long-term Liabilities and Deferred Credits,” related to our other postretirement benefit plans.

Amounts recognized in “Accumulated Other Comprehensive Loss” consist of:

	Successor Company					Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007
	(In millions)					(In millions)
Beginning Balance	$	12.0		$	-	$	44.0
Net (Gain)/Loss Arising During Period		26.4			12.0		(5.4	)
Amortization of (Gain)/Loss		(0.5	)		-		(2.0	)
Amortization of Prior Service Cost		-			-		0.7
Ending Balance	$	37.9		$	12.0	$	37.3

The estimated net loss for the postretirement benefit plans that will be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost over the next fiscal year is $3.0 million. NGPL PipeCo LLC expects to make contributions of approximately $8.7 million to the plan in 2009.

A one-percentage-point increase (decrease) in the assumed health care cost trend rate for each future year would have increased (decreased) the aggregate of the service and interest cost components of the 2008 net periodic postretirement benefit cost by approximately $5 $(4) thousand and would have increased (decreased) the accumulated postretirement benefit obligation as of December 31, 2008 by approximately $77 $(72) thousand.

The following net benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Fiscal Year	Expected Net Benefit Payments
	(In millions)
2009	$	7.6
2010	$	7.3
2011	$	7.2
2012	$	6.9
2013	$	6.8
2014-2017	$	31.2

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Actuarial Assumptions

The assumptions used to determine benefit obligations for the pension and postretirement benefit plans were:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Discount Rate		6.25	%		5.75	%		6.00	%		6.00	%
Expected Long-term Return on Assets		8.75	%		9.00	%		9.00	%		9.00	%
Rate of Compensation Increase (Pension Plan Only)		3.50	%		3.50	%		3.50	%		3.50	%

The assumptions used to determine net periodic benefit cost for the pension and postretirement benefits were:

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Discount Rate		5.75	%		6.00	%		6.00	%		5.75	%
Expected Long-term Return on Assets		9.00	%		9.00	%		9.00	%		9.00	%
Rate of Compensation Increase (Pension Plan Only)		3.50	%		3.50	%		3.50	%		3.50	%

The assumed healthcare cost trend rates for the postretirement plan were:

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
Healthcare Cost Trend Rate Assumed for Next Year		3.0%		3.0%		3.0%		3.0%
Rate to which the Cost Trend Rate is Assumed to Decline (Ultimate Trend Rate)		3.0%		3.0%		3.0%		3.0%
Year the Rate Reaches the Ultimate Trend Rate		2008		2007		2007		2006

Plan Investment Policies

The investment policies and strategies for the assets of our pension and retiree medical and retiree life insurance plans are established by the Fiduciary Committee (the “Committee”), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes.

As of December 31, 2008, the following target asset allocation ranges were in effect for our pension plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income –20%/30%/40%; Equity – 55%/65%/75% and Alternative Investments – 0%/5%/10%. As of December 31, 2008, the following target asset allocation ranges were in effect for our retiree medical and retiree life insurance plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income –20%/30%/40% and Equity – 60%/70%/80%. In order to achieve enhanced diversification, the equity category is further subdivided into sub-categories with respect to small cap vs. large cap, value vs. growth and international vs. domestic, each with its own target asset allocation.

In implementing its investment policies and strategies, the Committee has engaged a professional investment advisor to assist with its decision making process and has engaged professional money managers to manage plan assets. The Committee believes that such active investment management will achieve superior returns with comparable risk in comparison to passive management. Consistent with its goal of reasonable diversification, no manager of an equity portfolio for the plan is allowed to have more than 10% of the market value of the portfolio in a single security or weight a single economic sector more than twice the weighting of that sector in the appropriate market index. Finally, investment managers are not permitted to invest or

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engage in the following equity transactions unless specific permission is given in writing (which permission has not been requested or granted by the Committee to-date): derivative instruments, except for the purpose of asset value protection (such as the purchase of protective puts), direct ownership of letter stock, restricted stock, limited partnership units (unless the security is registered and listed on a domestic exchange), venture capital, short sales, margin purchases or borrowing money, stock loans and commodities. In addition, fixed income holdings in the following investments are prohibited without written permission: private placements, except medium-term notes and securities issued under SEC Rule 144a; foreign bonds (non-dollar denominated); municipal or other tax exempt securities, except taxable municipals; margin purchases or borrowing money to effect leverage in the portfolio; inverse floaters, interest only and principle only mortgage structures; and derivative investments (futures or option contracts) used for speculative purposes. Certain other types of investments such as hedge funds and land purchases are not prohibited as a matter of policy but have not, as yet, been adopted as an asset class or received any allocation of fund assets.

Return on Plan Assets

For the year ending December 31, 2008, our defined benefit pension plan yielded a weighted-average rate of return of (27.87%), below the expected rate of return on assets of 9.00%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of (25.45%), so our plans underperformed the benchmark balanced fund index. For the year ending December 31, 2008, our retiree medical and retiree life insurance plans yielded a weighted-average rate of return of (26.04%), below the expected rate of return on assets of 9.00%. Investment performance for a balanced fund comprised of a similar mix of assets yielded a weighted-average return of (22.55%), so our plans underperformed the benchmark balanced fund index.

At December 31, 2008, our pension plan assets consisted of 60.6% equity, 34.4% fixed income and 5.0% cash and cash equivalents, and our retiree medical and retiree life insurance plan assets consisted of 54.1% equity, 38.8% fixed income and 7.1% cash and cash equivalents. Historically over long periods of time, widely traded large cap equity securities have provided a return of 10%, while fixed income securities have provided a return of 6%, indicating that a long term expected return predicated on the asset allocation as of December 31, 2008 would be approximately 8.75% to 9.31% if investments were made in the broad indexes for our defined benefit pension plan, and 8.36% to 8.88% for our retiree medical and retiree life insurance plan. As reported in our 2007 Annual Report on Form 10-K, these expected returns as of December 31, 2007 were 9.6% to 9.8%. We arrived at an overall expected return of 9.0% for our periodic benefit cost calculations for 2008 and an overall expected return of 8.75% for our benefit obligation calculations as of December 31, 2008.

Kinder Morgan Energy Partners

Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partners of Trans Mountain Pipeline, L.P.) are sponsors of pension plans for eligible Trans Mountain employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. Kinder Morgan Energy Partners also provides postretirement benefits other than pensions for retired employees. Kinder Morgan Energy Partners’ combined net periodic benefit costs for these Trans Mountain pension and postretirement benefit plans for the year ended December 31, 2008, seven months ended December 31, 2007 and five months ended May 31, 2007 were approximately $3.5 million, $1.9 million and $1.3 million, respectively. As of December 31, 2008, Kinder Morgan Energy Partners estimates its overall net periodic pension and postretirement benefit costs for these plans for the year 2009 will be approximately $3.1 million, although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Kinder Morgan Energy Partners expects to contribute approximately $7.7 million to these benefit plans in 2009. Prior to the sale of Trans Mountain to Kinder Morgan Energy Partners on April 30, 2007 (refer to Note 10) the pension plans of Trans Mountain were part of the Terasen pension plans. Refer to the following discussion on the Terasen pension plans for 2006.

In connection with Kinder Morgan Energy Partners’ acquisition of SFPP, L.P., (“SFPP”) and Kinder Morgan Bulk Terminals, Inc. in 1998, Kinder Morgan Energy Partners acquired certain liabilities for pension and postretirement benefits. Kinder Morgan Energy Partners provides medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. Kinder Morgan Energy Partners also provides the same benefits to former salaried employees of SFPP. Additionally, Kinder Morgan Energy Partners will continue to fund these costs for those employees currently in the plan during their retirement years. SFPP’s postretirement benefit plan is frozen, and no additional participants may join the plan. The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Knight Inc. Retirement Plan. The benefits under this plan are based primarily upon years of service and final average pensionable earnings; however, benefit accruals were frozen as of December 31, 1998.

The net periodic benefit cost for the SFPP postretirement benefit plan was less than $0.1 million for the year ended December 31, 2008, and credits of $0.1 million, $0.1 million and $0.3 million for the seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively. The credits in 2006 and 2007 resulted in increases to income, largely due to amortizations of an actuarial gain and a negative prior service cost. As of December 31,

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2008, Kinder Morgan Energy Partners estimates its overall net periodic postretirement benefit cost for the SFPP postretirement benefit plan for the year 2009 will be a credit of approximately $0.1 million, however, this estimate could change if a future significant event would require a remeasurement of liabilities. In addition, Kinder Morgan Energy Partners expects to contribute approximately $0.3 million to this postretirement benefit plan in 2009.

As of December 31, 2008 and 2007, the recorded value of Kinder Morgan Energy Partners’ pension and postretirement benefit obligations for these plans was a combined $33.4 million and $37.5 million, respectively.

Multiemployer Plans

As a result of acquiring several terminal operations, primarily the acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, Kinder Morgan Energy Partners participates in several multi-employer pension plans for the benefit of employees who are union members. Kinder Morgan Energy Partners does not administer these plans and contributes to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans totaled $7.8 million, $2.5 million, $4.2 million and $6.3 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.

Terasen

Prior to the sale of Terasen Inc. and Terasen Pipelines (Corridor) Inc. on May 17, 2007 and June 15, 2007, respectively, (see Note 19) we were a sponsor of pension plans for eligible employees. Our expense for the Terasen Inc. and Corridor pension and other postretirement benefits plans for the period from January 1 to May 15, 2007 was $3.7 million and $11.1 million for the year ended December 31, 2006. After the sale of Terasen and Corridor we no longer had expenses or obligations related to these pension and other postretirement plans. The Terasen and Corridor plans included registered defined benefit pension plans, supplemental unfunded arrangements, which provide pension benefits in excess of statutory limits, and defined contributory plans. We also provided postretirement benefits other than pensions for retired employees.

17. Share-based Compensation

Kinder Morgan, Inc.

In March 2007, all stock options and restricted stock held by employees of our discontinued U.S. Retail operations became fully vested. In May 2007, all restricted stock units held by employees of our discontinued Terasen gas operations became fully vested and any contingent stock unit grants were fully expensed. Finally, on May 30, 2007, all remaining stock options and restricted stock became fully vested and were exercised upon the closing of the Going Private transaction. We recorded expense of $25.7 million during the five months ended May 31, 2007 related to the accelerated vesting of these awards.

Restricted stock and restricted stock unit grants issued in the periods presented below were under the following plans: The 1992 Non-Qualified Stock Option Plan for Non-Employee Directors (which plan has expired), the 1994 Kinder Morgan, Inc. Long-term Incentive Plan (which plan has expired), the Kinder Morgan, Inc. Amended and Restated 1999 Stock Plan and the Non-Employee Directors Stock Awards Plan. The 1994 plan, and the 1999 plan and the Non-Employee Directors Stock Awards Plan provided for the issuance of restricted stock. There were also two employee stock purchase plans, one for U.S. employees and one for Canada-based employees.

Over the years, the 1999 Stock Plan had been amended to increase shares available to grant, to allow for granting of restricted shares and effective January 18, 2006, had been amended to allow for the granting of restricted stock units to employees residing outside the United States. We stopped granting stock options after July 2004 and replaced option grants with grants of restricted stock and restricted stock units to fewer people and in smaller amounts. Our restricted stock and restricted stock unit grants generally had either a three-year or five-year cliff vesting.

For the five months ended May 31, 2007 and year ended December 31, 2006, we recognized stock option expense of $0.8 million and $5.0 million, respectively.

During 2006, we made restricted common stock grants to employees of 10,000 shares. These grants were valued at $1.0 million, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. Restricted stock grants made to employees vest over three or five year periods. During 2006, we made restricted common stock grants to our non-employee directors of 17,600 shares. These grants were valued at $1.7 million. All of the restricted stock grants made to non-employee directors vested during a six-month period. Expense related to restricted stock grants was recognized on a straight-line basis over the respective vesting periods. During the five months ended May 31, 2007 and year ended December 31, 2006, we amortized $5.0 million and $14.9 million, respectively, related to restricted stock grants.

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During 2006, we made restricted stock unit grants of 61,800 units. These grants were valued at $6.0 million, based on the closing market price of our common stock on either the date of grant or the measurement date, if different. During the five months ended May 31, 2007 and year ended December 31, 2006, we amortized $1.6 million and $3.4 million, respectively, related to restricted stock unit grants.

A summary of the status of our restricted stock and restricted stock unit plans at May 31, 2007 and December 31, 2006, and changes during the periods then ended is presented in the table below:

	Predecessor Company
	Five Months Ended May 31, 20071					Year Ended December 31, 2006
	Shares		Weighted Average Grant Date Fair Value			Shares		Weighted Average Grant Date Fair Value
	(Dollars in millions)
Outstanding at Beginning of Period	812,240		$	55.6		880,310		$	56.6
Granted	-			-		89,400			8.7
Reinstated	-			-		50,000			2.7
Vested	(59,117	)		(4.8	)	(193,620	)		(11.3	)
Forfeited	(12,016	)		(1.0	)	(13,850	)		(1.1	)
Outstanding at End of Period	741,107		$	49.8		812,240		$	55.6
Intrinsic Value of Restricted Stock Vested During the Period			$	3.6				$	19.2

_____________

1 As discussed above, all remaining restricted stock at the end of the period became fully vested and was exercised upon the closing of the Going Private transaction.

Contingent grants totaling an additional 178,000 shares of restricted common stock and 65,650 restricted stock units were granted in July 2006. Upon the closing of the Going Private transaction, these grants were replaced with the Long-term Incentive Retention Award plan (see Note 16).

A summary of the status of our stock option plans at May 31, 2007 and December 31, 2006, and changes during the periods then ended is presented as follows:

	Predecessor Company
	Five Months Ended May 31, 20071				Year Ended December 31, 2006
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at Beginning of Period	2,604,217		$	46.02	3,421,849		$	45.21
Granted	-		$	-	-		$	-
Exercised	(160,838	)	$	44.67	(618,746	)	$	44.82
Forfeited	(35,975	)	$	50.10	(198,886	)	$	41.95
Outstanding at End of Period	2,407,404		$	46.06	2,604,217		$	46.02
Exercisable at End of Period	2,183,379		$	44.55	2,310,392		$	44.49
Weighted-Average Fair Value of Options Granted			$	-			$	-
Aggregate Intrinsic Value of Options Exercisable at End of Period (in millions)			$	142.0			$	147.9
Intrinsic Value of Options Exercised During the Period (in millions)			$	9.9			$	34.1
Cash Received from Exercise of Options During the Period (in millions)			$	7.2			$	27.7

____________

1 As discussed above, all remaining stock options became fully vested and were exercised upon the closing of the Going Private transaction on May 31, 2007.

Beginning March 31, 2005, employees could purchase our common stock at a 5% discount, thus making the employee stock purchase plan a non-compensatory plan. Employees purchased 7,605 shares and 36,772 shares for the five months ended May 31, 2007 and year ended December 31, 2006, respectively. We also had a Foreign Subsidiary Employees Stock

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Purchase Plan for our employees working in Canada. This plan mirrored the Employee Stock Purchase Plan for our United States employees. Employees were eligible to participate in the program beginning April 1, 2006. Employees purchased 545 shares and 2,098 shares during the five months ended May 31, 2007 and year ended December 31, 2006.

Kinder Morgan Energy Partners

Kinder Morgan Energy Partners has three common unit-based compensation plans: A common unit option plan, the Directors’ Unit Appreciation Rights Plan and the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan.

The common unit option plan was established in 1998. The plan was authorized to grant up to 500,000 options to key personnel and terminated in March 2008. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date. No grants have been made under this plan since May 2000. During 2006, 4,200 options to purchase common units were cancelled or forfeited and 21,100 options to purchase common units were exercised at an average price of $19.67 per unit. The common units underlying these options had an average fair market value of $46.43 per unit. As of December 31, 2006, 2007 and 2008, there were no outstanding options under this plan.

The Directors’ Unit Appreciation Rights Plan was established on April 1, 2003. Pursuant to this plan, each of Kinder Morgan Management’s three non-employee directors was eligible to receive common unit appreciation rights. Upon the exercise of unit appreciation rights, Kinder Morgan Energy Partners will pay, within thirty days of the exercise date, the participant an amount of cash equal to the excess, if any, of the aggregate fair market value of the unit appreciation rights exercised as of the exercise date over the aggregate award price of the rights exercised. The fair market value of one unit appreciation right as of the exercise date will be equal to the closing price of one common unit on the New York Stock Exchange on that date. The award price of one unit appreciation right will be equal to the closing price of one common unit on the New York Stock Exchange on the date of grant. All unit appreciation rights granted vest on the six-month anniversary of the date of grant and have a ten-year term. During 2008, 10,000 unit appreciation rights were exercised by one director at an aggregate fair value of $60.32 per unit. During 2007, 7,500 unit appreciation rights were exercised by one director at an aggregate fair value of $53.00 per unit. No unit appreciation rights were exercised during 2006. As of December 31, 2008, 35,000 unit appreciation rights had been granted, vested and remained outstanding. In 2005, this plan was replaced with the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors, discussed following.

The Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan recognizes that the compensation to be paid to each non-employee director is fixed by the Kinder Morgan Management board, generally annually, and that the compensation is expected to include an annual retainer payable in cash. Pursuant to the plan, in lieu of receiving cash compensation, each non-employee director may elect to receive common units. A non-employee director may make a new election each calendar year. The total number of common units authorized under this compensation plan is 100,000. All common units issued under this plan are subject to forfeiture restrictions that expire six months from the date of issuance. A total of 16,868 common units were issued to non-employee directors in 2006, 2007 and 2008 as a result of their elections to receive common units in lieu of cash compensation.

18. Commitments and Contingent Liabilities

Operating Leases and Purchase Obligations

Expenses incurred under operating leases were $84.2 million for the year ended December 31, 2008, $43.8 million for the seven months ended December 31, 2007, $32.2 million for the five months ended May 31, 2007 and $53.5 million in 2006, of which $0.1 million in the seven months ended December 31, 2007, $1.2 million in the five months ended May 31, 2007 and $3.1 million in 2006 were associated with our discontinued operations. Future minimum commitments under major operating leases as of December 31, 2008 are as follows:

Year	Operating Leases
	(In millions)
2009	$	57.5
2010		54.5
2011		48.9
2012		44.8
2013		40.6
Thereafter		418.4
Total	$	664.7

We have not reduced our total minimum payments for future minimum sublease rentals, aggregating approximately $5.2 million. The remaining terms on our operating leases range from one to 61 years.

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Guarantee

As a result of our December 1999 sale of assets to ONEOK, Inc., ONEOK, Inc. became primarily obligated for the lease of the Bushton gas processing facility. We remain secondarily liable for the lease, which had a remaining minimum obligation of approximately $78.8 million at December 31, 2008, with remaining payments that average approximately $26.3 million per year through 2011.

Capital Expenditures Budget

Approximately $581.0 million of our consolidated capital expenditure budget for 2009 had been committed for the purchase of plant and equipment at December 31, 2008.

Commitments for Incremental Investment

We could be obligated (i) based on operational performance of the equipment at the Jackson, Michigan power generation facility to invest up to an additional $3 to $8 million per year for the next 10 years and (ii) based on cash flows generated by the facility, to invest up to an additional $25 million beginning in 2018, in each case in the form of an incremental preferred interest.

Contingent Debt

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

As of December 31, 2008, the debt facilities of Cortez Capital Corporation consisted of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125 million short-term commercial paper program; and (iii) a $125 million five-year committed revolving credit facility due December 22, 2009 (to support the above-mentioned $125 million commercial paper program). As of December 31, 2008, Cortez Capital Corporation had outstanding borrowings of $116.0 million under its five-year credit facility. The average interest rate on the Series D notes was 7.14% in 2008.

In October 2008, Standard & Poor’s Rating Services lowered Cortez Capital Corporation’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Cortez Capital Corporation is unable to access commercial paper borrowings; however, Kinder Morgan Energy Partners expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank credit facility.

With respect to Cortez Capital Corporation’s Series D notes, Shell Oil Company shares Kinder Morgan Energy Partners’ several guaranty obligations jointly and severally; however, Kinder Morgan Energy Partners is obligated to indemnify Shell for liabilities it incurs in connection with such guaranty. Kinder Morgan Energy Partners has an outstanding letter of credit issued by JP Morgan Chase in the amount of $26.8 million to secure Kinder Morgan Energy Partners’ indemnification obligations to Shell for 50% of the $53.6 million in principal amount of Series D notes outstanding as of December 31, 2008.

Nassau County, Florida Ocean Highway and Port Authority Debt – Kinder Morgan Energy Partners has posted a letter of credit as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida, where Kinder Morgan Energy Partners’ subsidiary, Nassau Terminals LLC, is the operator of the marine port facilities. The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020. Principal payments on the bonds are made on the first of December each year and corresponding reductions are made to the letter of credit.

In October 2008, pursuant to the standby purchase agreement provisions contained in the bond indenture—which require the sellers of those guarantees to buy the debt back—certain investors elected to put (sell) back their bonds at par plus accrued interest. A total principal and interest amount of $11.8 million was tendered and drawn against Kinder Morgan Energy Partners’ letter of credit and accordingly, Kinder Morgan Energy Partners paid this amount pursuant to the letter of credit reimbursement provisions. This payment reduced the face amount of Kinder Morgan Energy Partners’ letter of credit from $22.5 million to $10.7 million. However, the bonds were subsequently resold and as of December 31, 2008, Kinder Morgan Energy Partners was fully reimbursed for the prior letter of credit payments. As of December 31, 2008, this letter of credit had a face amount of $10.2 million.

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Rockies Express Pipeline LLC Debt – Pursuant to certain guaranty agreements, all three member owners of West2East Pipeline LLC (which owns all of the member interests in Rockies Express Pipeline LLC) have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in West2East Pipeline LLC, borrowings under Rockies Express Pipeline LLC’s (i) $2.0 billion five-year, unsecured revolving credit facility due April 28, 2011; (ii) $2.0 billion commercial paper program; and (iii) $600 million in principal amount of floating rate senior notes due August 20, 2009. The three member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners’ subsidiary Kinder Morgan W2E Pipeline LLC – 51%, a subsidiary of Sempra Energy – 25%, and a subsidiary of ConocoPhillips – 24%.

Borrowings under the Rockies Express Pipeline LLC commercial paper program and/or its credit facility are primarily used to finance the construction of the Rockies Express interstate natural gas pipeline and to pay related expenses. The credit facility, which can be amended to allow for borrowings up to $2.5 billion, supports borrowings under the commercial paper program, and borrowings under the commercial paper program reduce the borrowings allowed under the credit facility. The $600 million in principal amount of senior notes were issued on September 20, 2007. The notes are unsecured and are not redeemable prior to maturity. Interest on the notes is paid and computed quarterly at an interest rate of three-month LIBOR (with a floor of 4.25%) plus a spread of 0.85%.

Upon issuance of the notes, Rockies Express Pipeline LLC entered into two floating-to-fixed interest rate swap agreements having a combined notional principal amount of $600 million and maturity dates of August 20, 2009. On September 24, 2008, Rockies Express Pipeline LLC terminated one of the aforementioned interest rate swaps that had Lehman Brothers as the counterparty. The notional principal amount of the terminated swap agreement was $300 million. The remaining interest rate swap agreement effectively converts the interest expense associated with $300 million of these senior notes from its stated variable rate to a fixed rate of 5.47%.

In October 2008, Standard & Poor’s lowered Rockies Express Pipeline LLC’s short-term credit rating to A-3 from A-2. As a result of this revision and current commercial paper market conditions, Rockies Express Pipeline LLC is unable to access commercial paper borrowings, and as of December 31, 2008, there were no borrowings under its commercial paper program. However, Rockies Express Pipeline LLC expects that its financing and liquidity needs will continue to be met through borrowings made under its long-term bank credit facility and contributions by its equity investors.

As of December 31, 2008, in addition to the $600 million in floating rate senior notes, Rockies Express Pipeline LLC had outstanding borrowings of $1,561.0 million under its five-year credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent share of Rockies Express Pipeline LLC’s debt was $1,102.1 million (51% of total guaranteed borrowings). In addition, there is a letter of credit outstanding to support the construction of the Rockies Express pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million. Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.0 million (51% of the total face amount).

One of the Lehman entities was a lending bank with an approximate $41 million commitment to the Rockies Express Pipeline LLC $2.0 billion credit facility. The credit facility has been reduced by this amount. The commitments of the other banks remain unchanged and the facility is not defaulted.

Midcontinent Express Pipeline LLC Debt – Pursuant to certain guaranty agreements, each of the two member owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Midcontinent Express Pipeline LLC, borrowings under Midcontinent Express Pipeline LLC’s $1.4 billion three-year, unsecured revolving credit facility, entered into on February 29, 2008 and due February 28, 2011. The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent. Borrowings under the credit agreement will be used to finance the construction of the Midcontinent Express Pipeline and to pay related expenses. One of the Lehman entities was a lending bank with an approximately $100 million commitment to the Midcontinent Express $1.4 billion credit facility. Since declaring bankruptcy, Lehman has not met its obligations to lend under the credit facility and our credit facility has effectively been reduced by its commitment. The commitments of the other banks remain unchanged and the facility is not defaulted.

Midcontinent Express Pipeline LLC is an equity method investee of Kinder Morgan Energy Partners, and the two member owners and their respective ownership interests consist of the following: Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%. As of December 31, 2008, Midcontinent Express Pipeline LLC had $837.5 million borrowed under its three-year credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent share of Midcontinent Express Pipeline LLC’s debt was $418.8 million (50% of total borrowings). Furthermore, the revolving credit facility can be used for the issuance of letters of credit to support the construction of the Midcontinent Express Pipeline LLC, and as of December 31, 2008, a letter of credit having a face amount of $33.3 million was issued under the credit facility. Accordingly, as of December 31, 2008, Kinder Morgan Energy Partners’ contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).

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Standby Letters of Credit

Letters of credit totaling $405.8 outstanding as of December 31, 2008 consisted of the following: (i) a $100.0 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of Kinder Morgan Energy Partners’ West Coast Products Pipelines in the state of California; (ii) a $55.9 million letter of credit supporting Kinder Morgan Energy Partners’ pipeline and terminal operations in Canada; (iii) a combined $40.0 million in two letters of credit supporting Kinder Morgan Energy Partners’ hedging of energy commodity price risks; (iv) Kinder Morgan Energy Partners’ $30.3 million guarantee under letters of credit totaling $45.5 million supporting our International Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $26.8 million letter of credit supporting Kinder Morgan Energy Partners’ indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; (vi) four letters of credit totaling $25.8 million, required under provisions of our property and casualty, worker’s compensation and general liability insurance policies; (vii) a $25.4 million letter of credit supporting Kinder Morgan Energy Partners’ Kinder Morgan Liquids Terminals LLC New Jersey Economic Development Revenue Bonds; (viii) two letters of credit totaling $20.3 million supporting the subordination of operating fees payable to us for operation of the Jackson, Michigan power generation facility to payments due under the operating lease of the facilities; (ix) a $18.0 million letter of credit supporting Kinder Morgan Energy Partners’ Kinder Morgan Operating L.P. “B” tax-exempt bonds; (x) a combined $17.2 million in eight letters of credit supporting environmental and other obligations of Kinder Morgan Energy Partners and its subsidiaries; (xi) a $15.3 million letter of credit to fund the Debt Service Reserve Account required under Kinder Morgan Energy Partners’ Express pipeline system’s trust indenture; (xii) a $10.2 million letter of credit supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds; and (xiii), a $5.4 million letter of credit supporting Kinder Morgan Energy Partners’ Arrow Terminals, L.P. Illinois Development Revenue Bonds.

19. Business Segment Information

In accordance with the manner in which we manage our businesses, including the allocation of capital and evaluation of business segment performance, we report our operations in the following segments:

· Natural Gas Pipeline Company of America—after February 15, 2008, this segment consists of our 20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company of America and certain affiliates, collectively referred to as Natural Gas Pipeline Company of America or NGPL, a major interstate natural gas pipeline and storage system which we operate;

· Power—which consists of two natural gas-fired electric generation facilities;

· Products Pipelines–KMP—which consists of approximately 8,300 miles of refined petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various markets; plus approximately 60 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the United States;

· Natural Gas Pipelines–KMP—which consists of over 14,300 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;

· CO2–KMP—which produces, markets and transports, through approximately 1,300 miles of pipelines, carbon dioxide to oil fields that use carbon dioxide to increase production of oil; owns interests in and/or operates ten oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;

· Terminals–KMP—which consists of approximately 110 owned or operated liquids and bulk terminal facilities and more than 45 rail transloading and materials handling facilities located throughout the United States and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the United States and Canada; and

· Kinder Morgan Canada–KMP—which consists of over 700 miles of common carrier pipelines, originating at Edmonton, Alberta, for the transportation of crude oil and refined petroleum to the interior of British Columbia and to marketing terminals and refineries located in the greater Vancouver, British Columbia area and Puget Sound in Washington State; plus five associated product terminals. This segment also includes a one-third interest in an approximately 1,700-mile integrated crude oil pipeline and a 25-mile aviation turbine fuel pipeline serving the Vancouver International Airport.

On August 28, 2008, we sold our one-third interest in the net assets of the Express pipeline system (“Express”), as well as our full ownership of the net assets of the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. We accounted for this transaction as a transfer of net assets between entities under common control. Therefore, following our sale of Express and Jet Fuel to Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. The results of Express and Jet Fuel are now reported in the segment referred to as Kinder Morgan Canada–KMP. Previously, we reported the results of the equity investment in Express pipeline system in the Express segment and the results of Jet Fuel in the “Other” caption in the following tables.

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On February 15, 2008, we sold an 80% ownership interest in our NGPL business segment to Myria (see Note 10). We continue to operate NGPL’s assets pursuant to a 15-year operating agreement. Effective February 15, 2008, we began to account for the results of operations of the NGPL segment as an equity investment.

In November 2007, we signed a definitive agreement to sell our interests in three natural gas-fired power plants in Colorado to Bear Stearns. The sale was effective January 1, 2008.

On October 5, 2007, Kinder Morgan Energy Partners announced that it had completed the sale of the North System and also its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7 million in cash. Prior to its sale, the North System and the equity investment in the Heartland Pipeline were reported in the Products Pipelines–KMP business segment.

On April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan Energy Partners for approximately $550 million. The transaction was approved by the independent members of our board of directors and those of Kinder Morgan Management following the receipt, by each board, of separate fairness opinions from different investment banks. Due to the inclusion of Kinder Morgan Energy Partners and its subsidiaries in our consolidated financial statements, we accounted for this transaction as a transfer of net assets between entities under common control, Kinder Morgan Energy Partners recognized the Trans Mountain assets and liabilities acquired at our carrying amounts (historical cost) at the date of transfer. As discussed in Note 3, based on an evaluation of the fair value of the Trans Mountain pipeline system, a goodwill impairment charge of approximately $377.1 million was recorded in 2007. The results of Trans Mountain are now reported in the segment referred to as Kinder Morgan Canada–KMP. In prior filings, the Trans Mountain pipeline system was reported in the Trans Mountain–KMP business segment.

In March 2007, we completed the sale of our U.S. retail natural gas distribution and related operations to GE Energy Financial Services, a subsidiary of General Electric Company, and Alinda Investments LLC. Prior to its sale, we referred to these operations as the Kinder Morgan Retail business segment.

On March 5, 2007, we entered into a definitive agreement to sell Terasen Pipelines (Corridor) Inc. to Inter Pipeline Fund, a Canada-based company. This transaction closed on June 15, 2007 (see Note 11).

In February 2007, we entered into a definitive agreement, which closed on May 17, 2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company with investments in regulated distribution utilities. Execution of this sale agreement constituted a subsequent event of the type that, under GAAP, required us to consider the market value indicated by the definitive sales agreement in our 2006 goodwill impairment evaluation. Accordingly, based on the fair values of these reporting unit(s) derived principally from this definitive sales agreement, an estimated goodwill impairment charge of approximately $650.5 million was recorded in 2006.

The financial results of Terasen Gas, Corridor, Kinder Morgan Retail, the North System and the equity investment in the Heartland Pipeline Company have been reclassified to discontinued operations for all periods presented. See Note 11 for additional information regarding discontinued operations.

The accounting policies we apply in the generation of business segment earnings are generally the same as those applied to our consolidated operations and described in Note 1, except that (i) certain items below the “Operating Income” line (such as interest expense) are either not allocated to business segments or are not considered by management in its evaluation of business segment performance, (ii) equity in earnings of equity method investees are included in segment earnings (these equity method earnings are included in “Other Income and (Expenses)” in the accompanying Consolidated Statements of Operations), (iii) certain items included in operating income (such as general and administrative expenses and depreciation, depletion and amortization (“DD&A”)) are not considered by management in its evaluation of business segment performance and, thus, are not included in reported performance measures, (iv) gains and losses from incidental sales of assets are included in segment earnings and (v) our business segments that are also segments of Kinder Morgan Energy Partners include certain other income and expenses and income taxes in their segment earnings. With adjustment for these items, we currently evaluate business segment performance primarily based on segment earnings before DD&A (sometimes referred to in this report as EBDA) in relation to the level of capital employed. Beginning in 2007, the segment earnings measure was changed from segment earnings to segment earnings before DD&A for segments not also segments of Kinder Morgan Energy Partners. This change was made to conform our disclosure to the internal reporting we use as a result of the Going Private transaction.

This segment measure change has been reflected in the prior periods shown in this document in order to achieve comparability. Because Kinder Morgan Energy Partners’ partnership agreement requires it to distribute 100% of its available cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’ available cash consists primarily of all of its cash receipts, less cash disbursements and changes in reserves), we consider each period’s earnings before all non-cash depreciation, depletion and amortization expenses to be an important measure of business segment performance for our

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segments that are also segments of Kinder Morgan Energy Partners. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value.

During 2008, 2007 and 2006, we did not have revenues from any single customer that exceeded 10% of our consolidated operating revenues.

Financial information by segment follows (in millions):

	Successor Company						Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007			Five Months Ended May 31, 2007			Year Ended December 31, 2006
Segment Earnings (Loss) before Depreciation, Depletion, Amortization and Amortization of Excess Cost of Equity Investments
NGPL1	$	129.8		$	422.8		$	267.4		$	603.5
Power		5.7			13.4			8.9			23.2
Products Pipelines–KMP2,3		(722.0	)		162.5			224.4			467.9
Natural Gas Pipelines–KMP2,3		(1,344.3	)		373.3			228.5			574.8
CO2–KMP2		896.1			433.0			210.0			488.2
Terminals–KMP2,3		(156.5	)		243.7			172.3			408.1
Kinder Morgan Canada–KMP2,4		152.0			58.8			(332.0	)		95.1
Total Segment Earnings (Loss) Before DD&A		(1,039.2	)		1,707.5			779.5			2,660.8
Depreciation, Depletion and Amortization		(918.4	)		(472.3	)		(261.0	)		(531.4	)
Amortization of Excess Cost of Equity Investments		(5.7	)		(3.4	)		(2.4	)		(5.6	)
Other Operating Income (Loss)		39.0			(0.3	)		2.9			6.8
General and Administrative Expenses		(352.5	)		(175.6	)		(283.6	)		(305.1	)
Interest and Other, Net5,6		(623.6	)		(586.4	)		(257.5	)		(594.0	)
Add Back Income Tax Expense Included in Segments Above2		2.4			44.0			15.6			29.0
Income (Loss) from Continuing Operations Before Income Taxes	$	(2,898.0	)	$	513.5		$	(6.5	)	$	1,260.5

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
Revenues from External Customers
NGPL1	$	132.1	$	752.4	$	424.5	$	1,114.4
Power		44.0		40.2		19.9		60.0
Products Pipelines–KMP		815.9		471.5		331.8		732.5
Natural Gas Pipelines–KMP		8,422.0		3,825.9		2,637.6		6,558.4
CO2–KMP		1,269.2		605.9		324.2		736.5
Terminals–KMP		1,172.7		598.8		364.2		864.1
Kinder Morgan Canada–KMP		198.9		100.0		62.9		140.8
Other		40.0		-		-		1.9
Total Revenues	$	12,094.8	$	6,394.7	$	4,165.1	$	10,208.6

	Successor Company					Predecessor Company
	Year Ended December 31, 2008			Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
Intersegment Revenues
NGPL1	$	0.9		$	4.8	$	2.0	$	3.6
Natural Gas Pipelines–KMP		-			-		3.0		19.3
Terminals–KMP		0.9			0.4		0.3		0.7
Other		(0.9	)		-		-		-
Total Intersegment Revenues	$	0.9		$	5.2	$	5.3	$	23.6

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	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007			Year Ended December 31, 2006
Depreciation, Depletion and Amortization
NGPL1	$	9.3	$	42.3	$	45.3		$	104.5
Power		-		0.2		(4.2	)		2.1
Products Pipelines–KMP		116.9		58.1		33.6			74.0
Natural Gas Pipelines–KMP		99.9		52.3		26.8			65.4
CO2–KMP		498.1		243.5		116.3			190.9
Terminals–KMP		157.4		62.1		34.4			74.6
Kinder Morgan Canada–KMP		36.7		13.5		8.2			19.4
Other		0.1		0.3		0.6			0.5
Total Consolidated Depreciation, Depletion and Amortization	$	918.4	$	472.3	$	261.0		$	531.4

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
Capital Expenditures
NGPL1	$	10.3	$	152.0	$	77.3	$	193.4
Power		-		-		-		-
Products Pipelines–KMP		221.7		179.9		79.5		196.0
Natural Gas Pipelines–KMP		946.5		197.4		66.6		271.6
CO2–KMP		542.6		249.2		133.3		283.0
Terminals–KMP		454.1		310.1		169.9		307.7
Kinder Morgan Canada–KMP		368.1		196.7		109.0		123.8
Other		2.0		1.7		17.2		0.1
Total Consolidated Capital Expenditures	$	2,545.3	$	1,287.0	$	652.8	$	1,375.6

	Successor Company				Predecessor Company
	2008		2007		2006
Assets at December 31
NGPL1	$	717.3	$	720.0	$	5,728.9
Power		58.9		120.6		387.4
Products Pipelines–KMP		5,526.4		6,941.4		4,812.9
Natural Gas Pipelines–KMP		7,748.1		8,439.8		3,796.6
CO2–KMP		4,478.7		3,919.2		1,875.6
Terminals–KMP		4,327.8		4,643.3		2,564.1
Kinder Morgan Canada–KMP		1,583.9		1,888.3		2,555.1
Total segment assets		24,441.1		26,672.6		21,720.6
Assets Held for Sale		-		8,987.9		510.2
Other7		1,003.8		440.5		4,564.8
Total Consolidated Assets	$	25,444.9	$	36,101.0	$	26,795.6

___________

1 Effective February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC to Myria. As a result of the sale, beginning February 15, 2008, we account for our 20% ownership interest in NGPL PipeCo LLC as an equity method investment and 100% of NGPL revenues, earnings and assets prior to the sale, are included in the above tables.

2 Kinder Morgan Energy Partners’ income taxes expenses for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 were $2.4 million, $44.0 million, $15.6 million and $29.0 million, respectively, and are included in segment earnings.

3 2008 includes non-cash goodwill impairment charges (see Note 3).

4 Five months ended May 31, 2007 includes a non-cash goodwill impairment charge (see Note 3).

5 Includes interest expense and miscellaneous other income and expenses not allocated to business segments.

6 Results for 2006 include a reduction in pre-tax income of $22.3 million ($14.1 million after tax) resulting from non-cash charges to mark to market certain interest rate swaps

7 Includes assets of discontinued operations, cash, restricted deposits, market value of derivative instruments (including interest rate swaps) and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments.

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Geographic Information

Prior to 2005, all but an insignificant amount of our assets and operations were located in the continental United States. Upon our acquisition of Terasen on November 30, 2005, we obtained significant assets and operations in Canada. However, that percent has declined in 2007 relative to 2006 with the sale of two significant portions of our Canadian assets during the year. Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions).

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
Revenues from External Customers
United States	$	11,804.2	$	6,239.7	$	4,086.6	$	10,045.9
Canada		269.3		143.5		70.5		143.2
Mexico and the Netherlands		21.3		11.5		8.0		19.5
Total Consolidated Revenues from External Customers	$	12,094.8	$	6,394.7	$	4,165.1	$	10,208.6

	Successor Company				Predecessor Company
	2008		2007		2006
Long-lived Assets at December 311
United States	$	17,511.1	$	16,051.9	$	16,779.7
Canada		1,568.7		1,565.8		4,605.8
Mexico and the Netherlands		97.7		88.2		117.0
Total Consolidated Long-lived Assets	$	19,177.5	$	17,705.9	$	21,502.5

____________

1 Long-lived assets exclude goodwill and other intangibles, net.

20.  Regulatory Matters

The tariffs we charge for transportation on our interstate common carrier pipelines are subject to rate regulation by the FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and nondiscriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expanded the circumstances under which interstate petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2008, 2007 and 2006, the application of the indexing methodology did not significantly affect tariff rates on our interstate petroleum products pipelines.

Below is a brief description of our ongoing regulatory matters, including any material developments that occurred during 2008. This note also contains a description of any material regulatory matters initiated during 2008 in which we are involved.

FERC Order No. 2004/717

Since November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C and 2004-D, adopting new Standards of Conduct as applied to natural gas pipelines. The primary change from existing regulation was to make such standards applicable to an interstate natural gas pipeline’s interaction with many more affiliates (referred to as “energy affiliates”). The Standards of Conduct require, among other things, separate staffing of interstate pipelines and their energy affiliates (but support functions and senior management at the central corporate level may be shared) and strict limitations on communications from an interstate pipeline to an energy affiliate.

However, on November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A, 2004-B, 2004-C and 2004-D as applied to natural gas pipelines, and remanded these same orders back to the FERC.

On October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating Order No. 2004’s concept of Energy Affiliates and corporate separation in favor of an employee functional approach as used in Order No. 497. A transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. The final rule also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, the final rule requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing

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function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. This rule became effective on November 26, 2008.

Notice of Inquiry – Financial Reporting

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

On September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a proposed rule that would revise its financial forms to require that additional information be reported by natural gas companies. The proposed rule would require, among other things, that natural gas companies (i) submit additional revenue information, including revenue from shipper-supplied gas, (ii) identify the costs associated with affiliate transactions and (iii) provide additional information on incremental facilities and on discounted and negotiated rates. The FERC proposed an effective date of January 1, 2008, which means that forms reflecting the new requirements for 2008 would be filed in early 2009. Comments on the proposed rule were filed by numerous parties on November 13, 2007.

On March 21, 2008, the FERC issued a Final Rule regarding changes to the Form 2, 2-A and 3Q. The revisions were designed to enhance the forms’ usefulness by updating them to reflect current market and cost information relevant to interstate pipelines and their customers. The rule is effective January 1, 2008 with the filing of the revised Form 3-Q beginning with the first quarter of 2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed by April 18, 2009. On June 20, 2008, the FERC issued an Order Granting in Part and Denying in Part Rehearing and Granting Request for Clarification. No substantive changes were made to the March 21, 2008 Final Rule.

Notice of Inquiry – Fuel Retention Practices

On September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on whether it should change its current policy and prescribe a uniform method for all interstate gas pipelines to use in recovering fuel gas and gas lost and unaccounted for. The Notice of Inquiry included numerous questions regarding fuel recovery issues and the effects of fixed fuel percentages as compared with tracking provisions. Comments on the Notice of Inquiry were filed by numerous parties on November 30, 2007. On November 20, 2008, the FERC issued an order terminating the inquiry.

Notice of Proposed Rulemaking – Promotion of a More Efficient Capacity Release Market-Order 712

On November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations concerning the release of firm capacity by shippers on interstate natural gas pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling on capacity release transactions of one year or less. Additionally, the FERC proposes to exempt capacity releases made as part of an asset management arrangement from the prohibition on tying and from the bidding requirements of Section 284.8. Initial comments were filed by numerous parties on January 25, 2008. On June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to the capacity release program. The FERC permitted market based pricing for short-term capacity releases of a year or less. Long-term capacity releases and a pipeline’s sale of its own capacity remain subject to a price cap. The ruling would facilitate asset management arrangements by relaxing the FERC’s prohibitions on tying and on its bidding requirements for certain capacity releases. The FERC further clarified that its prohibition on tying does not apply to conditions associated with gas inventory held in storage for releases for firm storage capacity. Finally, the FERC waived the prohibition on tying and bidding requirements for capacity releases made as part of state-approved retail open access programs. The final rule became effective on July 30, 2008.

On November 20, 2008, the FERC issued an order generally denying requests for rehearing and/or clarification that had been filed. The FERC reaffirmed its final rule, Order 712, and denied requests for rehearing stating the removal of the rate ceiling for short-term capacity release transactions is designed to extend to capacity release transactions, the pricing flexibility already available to pipelines through negotiated rates without compromising the fundamental protection provided by the availability of recourse rate service. Additionally, the FERC clarified several areas of the rule as it relates to asset management arrangements.

Notice of Proposed Rulemaking – Natural Gas Price Transparency

On April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos. RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section 23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC proposed to revise its regulations to (i) require that intrastate pipelines post daily the capacities of, and volumes flowing through, their major receipt and delivery points and mainline segments in order to make available the information to track daily flows of natural gas throughout the United States; and (ii) require that buyers and sellers of more than a de minimis volume of natural gas report annual numbers and volumes of relevant transactions to the FERC in order to make

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possible an estimate of the size of the physical U.S. natural gas market, assess the importance of the use of index pricing in that market and determine the size of the fixed-price trading market that produces the information. The FERC believes these revisions to its regulations will facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. Initial comments were filed on July 11, 2007 and reply comments were filed on August 23, 2007. In addition, the FERC conducted an informal workshop in this proceeding on July 24, 2007, to discuss implementation and other technical issues associated with the proposals set forth in the notice of proposed rulemaking.

In addition, on December 21, 2007, the FERC issued a new notice of proposed rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new notice of proposed rulemaking proposes to exempt from the daily posting requirements those non-interstate pipelines that (i) flow less than ten million MMBtus of natural gas per year, (ii) fall entirely upstream of a processing plant and (iii) deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users. However, the new notice of proposed rulemaking expands the proposal to require that both interstate and non-exempt non-interstate pipelines post daily the capacities of, volumes scheduled at, and actual volumes flowing through, their major receipt and delivery points and mainline segments. Initial comments were filed by numerous parties on March 13, 2008. A Technical Conference was held on April 3, 2008. Numerous reply comments were received on April 14, 2008.

On December 26, 2007, the FERC issued Order No. 704 in this docket implementing only the annual reporting provisions of the notice of proposed rulemaking with minimal changes to the original proposal. The order became effective February 4, 2008. The initial report is due May 1, 2009 for calendar year 2008. Subsequent reports are due by May 1 of each year for the previous calendar year. Order 704 will require most, if not all Kinder Morgan natural gas pipelines to report annual volumes of relevant transactions to the FERC. Technical workshops were held on April 22, 2008 and May 19, 2008. The FERC issued Order 704-A on September 18, 2008. This order generally affirmed the rule, while clarifying what information certain natural gas market participants must report in Form 552. The revisions pertain to the reporting of transactions occurring in calendar year 2008. Order 704-A became effective October 27, 2008.

On November 20, 2008, the FERC issued Order 720, which is the final rule in the Docket No. RM08-2-000 proceeding. The final rule established new reporting requirements for interstate and major non-interstate pipelines. A major non-interstate pipeline is defined as a pipeline who delivers annually more than 50 million MMBtus of natural gas measured in average deliveries for the previous three calendar years. Interstate pipelines will be required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines will be required to post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMbtus of natural gas per day or greater when gas is scheduled at the point. The final rule became effective January 27, 2009 for interstate pipelines. Non-major interstate pipelines must comply with the requirements of Order 720 within 150 days following the issuance of an order addressing the pending request for rehearing.

FERC Equity Return Allowance

On April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that allows master limited partnerships to be included in proxy groups for the purpose of determining rates of return for both interstate natural gas and oil pipelines. Additionally, the policy statement concluded that (i) there should be no cap on the level of distributions included in the FERC’s current discounted cash flow methodology, (ii) the Institutional Brokers Estimated System forecasts should remain the basis for the short-term growth forecast used in the discounted cash flow calculation, (iii) there should be an adjustment to the long-term growth rate used to calculate the equity cost of capital for a master limited partnership, specifically the long-term growth rate would be set at 50% of the gross domestic product and (iv) there should be no modification to the current respective two-thirds and one-third weightings of the short-term and long-term growth factors. Additionally, the FERC decided not to explore other methods for determining a pipeline’s equity cost of capital at this time. The policy statement governs all future gas and oil rate proceedings involving the establishment of a return on equity, as well as those cases that are currently pending before either the FERC or an administrative law judge. On May 19, 2008, an application for rehearing was filed by The American Public Gas Association. On June 13, 2008, the FERC dismissed the request for rehearing.

Notice of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines

On September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA, published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to extend certain threat-focused pipeline safety regulations to rural onshore low-stress hazardous liquid pipelines within a prescribed buffer of previously defined U.S. states. Low-stress hazardous liquid pipelines, except those in populated areas or that cross commercially navigable waterways, have not been subject to the safety regulations in PHMSA 49 C.F.R. Part 195.1. According to the PHMSA, unusually sensitive areas are areas requiring extra protection because of the presence of sole-source drinking water resources, endangered species, or other ecological resources that could be adversely affected by accidents or leaks occurring on hazardous liquid pipelines.

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The notice proposed to define a category of “regulated rural onshore low-stress lines” (rural lines operating at or below 20% of specified minimum yield strength, with a diameter of eight and five-eighths inches or greater, located in or within a quarter-mile of a U.S. state) and to require operators of these lines to comply with a threat-focused set of requirements in Part 195 that already apply to other hazardous liquid pipelines. The proposed safety requirements addressed the most common threats—corrosion and third party damage—to the integrity of these rural lines. The proposal is intended to provide additional integrity protection, to avoid significant adverse environmental consequences, and to improve public confidence in the safety of unregulated low-stress lines.

Since the new notice is a proposed rulemaking in which the PHMSA will consider initial and reply comments from industry participants, it is not clear what impact the final rule will have on the business of our intrastate and interstate liquids pipeline companies.

Kinder Morgan Liquid Terminals – U.S. Department of Transportation Jurisdiction

With regard to several of our liquids terminals, we are working with the U.S. Department of Transportation, referred to in this report as the DOT, to supplement our compliance program for certain of our tanks and internal piping. We anticipate the program will call for incremental capital spending over the next several years to improve and/or add to our facilities. These improvements will enhance the tanks and piping previously considered outside the jurisdiction of DOT to conduct DOT jurisdictional transfers of products. Our original estimate called for an incremental $3 million to $5 million of annual capital spending over the next six to ten years for this work; however, we continue to assess the amount of capital that will be required and the amount may exceed our original estimate.

Natural Gas Pipeline Expansion Filings

TransColorado Pipeline

On April 19, 2007, the FERC issued an order approving TransColorado Gas Transmission Company LLC’s application for authorization to construct and operate certain facilities comprising its proposed “Blanco-Meeker Expansion Project.” This project provides for the transportation of up to approximately 250 million cubic feet per day of natural gas from the Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing interstate pipeline for delivery to the Rockies Express Pipeline at an existing point of interconnection located in the Meeker Hub in Rio Blanco County, Colorado. Construction commenced on May 9, 2007, and the project was completed and entered service January 1, 2008.

Rockies Express Pipeline-Currently Certificated Facilities

Kinder Morgan Energy Partners operates and owns a 51% ownership interest in West2East Pipeline LLC, a limited liability company that is the sole owner of Rockies Express Pipeline LLC, and operates Rockies Express Pipeline. ConocoPhillips owns a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When construction of the entire Rockies Express Pipeline project is completed, Kinder Morgan Energy Partners’ ownership interest will be reduced to 50% at which time the capital accounts of West2East Pipeline LLC will be trued up to reflect Kinder Morgan Energy Partners’ 50% economics in the project. According to the provisions of current accounting standards, because Kinder Morgan Energy Partners will receive 50% of the economic benefits from the Rockies Express project on an ongoing basis, Kinder Morgan Energy Partners is not considered the primary beneficiary of West2East Pipeline LLC and thus, accounts for its 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 Pipeline LLC was granted authorization to construct and operate approximately 136 miles of pipeline extending northward from the Meeker Hub, located at the northern end of Kinder Morgan Energy Partners’ 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 Pipeline LLC was authorized to construct three compressor stations, referred to as the Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter stations went into service in January 2008. Construction of the Big Hole compressor station commenced in the second quarter of 2008, and the expected in service date for the compressor station is in the second quarter of 2009.

Rockies Express Pipeline-West Project

On April 19, 2007, the FERC issued a final order approving the Rockies Express Pipeline LLC application for authorization to construct and operate certain facilities comprising its proposed “Rockies Express-West” project. This project is the first planned segment extension of the Rockies Express’ facilities described above, and it is comprised of approximately 713 miles of 42-inch diameter pipeline extending from the Cheyenne Hub to an interconnection with Panhandle Eastern Pipe Line

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located in Audrain County, Missouri. The project also includes certain improvements to existing Rockies Express facilities located to the west of the Cheyenne Hub. Construction on Rockies Express-West commenced on May 21, 2007. Rockies Express-West began interim service for up to 1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles of pipe on January 12, 2008. The project commenced deliveries to Panhandle Eastern Pipe Line, at Audrain County, Missouri, on the remaining 210 miles of pipe on May 20, 2008. The Rockies Express-West pipeline segment transports approximately 1.5 million cubic feet per day of natural gas across five states: Wyoming, Colorado, Nebraska, Kansas and Missouri.

Rockies Express Meeker to Cheyenne Expansion Project

Pursuant to certain rights exercised by Encana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities, Rockies Express Pipeline LLC is requesting authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project. The proposed expansion will consist of additional natural gas compression at its Big Hole compressor station located in Moffat County, Colorado and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) from the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion is fully contracted and is expected to be operational in April 2010. The total estimated cost for the proposed project is approximately $78 million. Rockies Express Pipeline LLC submitted a FERC application seeking approval to construct and operate this expansion on February 3, 2009.

Rockies Express Pipeline-East Project

On April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the Rockies Express-East Project. The Rockies Express-East Project will be comprised of approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio and will be capable of transporting approximately 1.8 billion cubic feet per day of natural gas.

By order issued May 30, 2008, the FERC authorized the certificate to construct the Rockies Express Pipeline-East Project. Construction commenced on the Rockies Express-East pipeline segment on June 26, 2008. Delays in securing permits and regulatory approvals, as well as weather-related delays, have caused Rockies Express Pipeline LLC to set revised project completion dates. Rockies Express-East is currently projected to commence service on April 1, 2009 to interconnects upstream of Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15, 2009, with final completion and deliveries to Clarington, Ohio commencing by November 1, 2009.

On October 31, 2008, Rockies Express Pipeline LLC filed an amendment to its certificate application, seeking authorization to revise its tariff-based recourse rates for transportation service on the Rockies Express Pipeline-East Project facilities to reflect updated construction costs for the project. The proposed amendment is pending FERC approval.

Current market conditions for consumables, labor and construction equipment along with certain provisions in the final regulatory orders have resulted in increased costs for the project and have impacted certain projected completion dates. Our current estimate of total completed costs on the Rockies Express Pipeline Project is approximately $6.3 billion including expansion (consistent with Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings release).

Kinder Morgan Interstate Gas Transmission Pipeline

On August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline LLC (referred to in this report as KMIGT) filed in FERC Docket CP07-430, for regulatory approval to construct and operate a 41-mile natural gas pipeline from the Cheyenne Hub to markets in and around Greeley, Colorado, referred to in this report as the Colorado Lateral. When completed, the Colorado Lateral will provide firm transportation of up to 55 million cubic feet per day to a local utility under long-term contract. The FERC issued a draft environmental assessment on the project on January 11, 2008, and comments on the project were received February 11, 2008. On February 21, 2008, the FERC granted the certificate application. On July 8, 2008, in response to a rehearing request by Public Service Company of Colorado (referred to in this report as PSCo) the FERC granted rehearing and denied KMIGT recovery in initial transportation rates $6.2 million in costs associated with non-jurisdictional laterals constructed by KMIGT to serve Atmos. The recourse rate adjustment does not have any material effect on the negotiated rate paid by Atmos to KMIGT or the economics of the project. On July 25, 2008, KMIGT filed an amendment to its certification application seeking authorization to revise its initial rates for transportation service on the Colorado Lateral to reflect updated construction costs for jurisdictional mainline facilities. The FERC approved the revised initial recourse rates on August 22, 2008.

PSCo, a competitor serving markets off the Colorado Lateral, also filed a complaint before the State of Colorado Public Utilities Commission (“CoPUC”) against Atmos, the anchor shipper on the project. The CoPUC conducted a hearing on

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April 14, 2008 on the complaint. On June 9, 2008, PSCo also filed before the CoPUC seeking a temporary cease and desist order to halt construction of the lateral facilities being constructed by KMIGT to serve Atmos. Atmos filed a response to that motion on June 24, 2008. By order dated June 27, 2008 an administrative law judge for the CoPUC denied PSCo’s request for a cease and desist order. On September 4, 2008, an administrative law judge for the CoPUC issued an order wherein it denied PSCo’s claim to exclusivity to serve Atmos and the Greeley market area but affirmed PSCo’s claim that Atmos’ acquisition of the delivery laterals is not in the ordinary course of business and requires separate approvals. Accordingly, Atmos may require a certificate of public convenience and necessity (“CPCN”) related to the delivery lateral facilities from KMIGT. While the need for approvals by Atmos before the CoPUC remains pending, service on the subject facilities commenced in November 2008.

On December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its system in Nebraska to serve incremental ethanol and industrial load. No protests to the application were filed and the project was approved by the FERC. Construction commenced on April 9, 2008. These facilities went into service in October 2008.

Kinder Morgan Louisiana Pipeline

On September 8, 2006, in FERC Docket No. CP06-449-000, Kinder Morgan Louisiana Pipeline LLC filed an application with the FERC requesting approval to construct and operate the Kinder Morgan Louisiana Pipeline. The natural gas pipeline will extend approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana and will provide interconnects with many other natural gas pipelines, including NGPL. The project is supported by fully subscribed capacity andlong-term customer commitments with Chevron and Total. The entire estimated project cost is now expected to be approximately $950 million (consistent with Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings press release), and it is expected to be fully operational during the third quarter of 2009.

On March 15, 2007, the FERC issued a preliminary determination that the authorizations requested, subject to some minor modifications, will be in the public interest. This order does not consider or evaluate any of the environmental issues in this proceeding. On April 19, 2007, the FERC issued the final environmental impact statement, or (“EIS”), which addressed the potential environmental effects of the construction and operation of the Kinder Morgan Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of the National Environmental Policy Act. It concluded that approval of the Kinder Morgan Louisiana Pipeline project would have limited adverse environmental impacts. On June 22, 2007, the FERC issued an order granting construction and operation of the project. Kinder Morgan Louisiana Pipeline officially accepted the order on July 10, 2007.

On July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the Kinder Morgan Louisiana Pipeline system to reflect updated construction costs for the project. The amendment was accepted by the FERC on August 14, 2008. On December 30, 2008, KMLP filed a second amendment to its certificate application, seeking authorization to revise its initial rates for transportation service on the KMLP system to reflect an additional increase in projected construction costs for the project. The filing is still pending.

Midcontinent Express Pipeline LLC

On October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC (“Midcontinent Express Pipeline”) filed an application with the FERC requesting a certificate of public convenience and necessity that would authorize construction and operation of the approximately 500-mile Midcontinent Express Pipeline natural gas transmission system.

The Midcontinent Express Pipeline will create long-haul, firm transportation takeaway capacity either directly or indirectly connected to natural gas producing regions located in Texas, Oklahoma and Arkansas. The pipeline will originate in southeastern Oklahoma and traverse east through Texas, Louisiana, Mississippi, and terminate at an interconnection with the Transco Pipeline near Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture between Kinder Morgan Energy Partners and Energy Transfer Partners, L.P., and it has a total capital cost of approximately $2.2 billion including the expansion capacity.

On July 25, 2008, the FERC approved the application made by Midcontinent Express Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline natural gas transmission system along with the lease of 272 Mcf of capacity on the Oklahoma intrastate system of Enogex Inc. Initial design capacity for the pipeline was 1.5 Bcf of natural gas per day, which was fully subscribed with long-term binding commitments from creditworthy shippers. A successful binding open season was completed in July 2008, which will increase the main segment of the pipeline’s capacity to 1.8 Bcf per day, subject to regulatory approval.

Midcontinent Express Pipeline accepted the FERC Certificate on July 30, 2008. Mobilization for construction of the pipeline began in the third quarter of 2008, and subject to the receipt of regulatory approvals, interim service on the first portion of the

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pipeline is expected to be available by the second quarter of 2009 with full in service in the third quarter of 2009. On January 9, 2009, Midcontinent Express filed an amendment to its original certificate application requesting authorization to revise its initial rates for transportation service on the pipeline system to reflect an increase in projected construction costs for the project. The filing is still pending.

On January 30, 2009, Midcontinent Express Pipeline filed a certificate application in Docket No. CP09-56-000 requesting authorization to increase the capacity in Zone 1 from 1.5 Bcf to 1.8 Bcf/d. The Application is still pending.

Kinder Morgan Texas Pipeline LLC

On May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000 a petition seeking market-based rate authority for firm and interruptible storage services performed under section 311 of the Natural Gas Policy Act of 1978 (NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas, and at the Markham Gas Storage Facility in Matagorda County, Texas. On October 3, 2008, the FERC approved this petition effective May 30, 2008.

21. Litigation, Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2008. This note also contains a description of any material legal proceeding initiated during 2008 in which we are involved.

Following is a listing of certain current FERC proceedings pertaining to Kinder Morgan Energy Partners’ operations:

Proceedings	Complainants/Protestants	Defendants
FERC Docket No. OR92-8, et al.	Chevron; Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco (Ultramar is an intervenor)	SFPP
FERC Docket No. OR92-8-025	BP WCP; ExxonMobil ; Chevron; ConocoPhillips; and Ultramar	SFPP
FERC Docket No. OR96-2, et al.	All Shippers except Chevron (which is an intervenor)	SFPP
FERC Docket Nos. OR02-4 and OR03-5	Chevron	SFPP
FERC Docket No. OR04-3	America West Airlines; Southwest Airlines; Northwest Airlines; and Continental Airlines	SFPP
FERC Docket Nos. OR03-5, OR05-4 and OR05-5	BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)	SFPP
FERC Docket No. OR03-5-001	BP WCP; ExxonMobil; and ConocoPhillips (other shippers intervened)	SFPP
FERC Docket No. OR07-1	Tesoro	SFPP
FERC Docket No. OR07-2	Tesoro	SFPP
FERC Docket No. OR07-3	BP WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing	SFPP
FERC Docket No. OR07-4	BP WCP; Chevron; and ExxonMobil	SFPP; Kinder Morgan G.P., Inc.; and Kinder Morgan, Inc.
FERC Docket Nos. OR07-5 and OR07-7 (consolidated)	ExxonMobil and Tesoro	Calnev; Kinder Morgan G.P., Inc.; and Kinder Morgan, Inc.
FERC Docket No. OR07-6	ConocoPhillips	SFPP
FERC Docket Nos. OR07-8 and OR07-11 (consolidated)	BP WCP and ExxonMobil	SFPP
FERC Docket No. OR07-9	BP WCP	SFPP
FERC Docket No. OR07-14	BP WCP and Chevron	SFPP; Calnev; and several affiliates
FERC Docket No. OR07-16	Tesoro	Calnev
FERC Docket No. OR07-18	Airline Complainants; Chevron; and Valero Marketing	Calnev
FERC Docket No. OR07-19	ConocoPhillips	Calnev
FERC Docket No. OR07-20	BP WCP	SFPP
FERC Docket No. OR07-22	BP WCP	Calnev

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FERC Docket No. OR08-13	BP WCP and ExxonMobil	SFPP
FERC Docket No. OR08-15	BP WCP and ExxonMobil	SFPP
FERC Docket No. IS05-230 (North Line rate case)	Shippers	SFPP
FERC Docket No. IS05-327	Shippers	SFPP
FERC Docket No. IS06-283 (East Line rate case)	Shippers	SFPP
FERC Docket No. IS06-296	ExxonMobil	Calnev
FERC Docket No. IS06-356	Shippers	SFPP
FERC Docket No. IS07-137 (Ultra Low Sulfur Diesel (ULSD) surcharge)	Shippers	SFPP
FERC Docket No. IS07-229	BP WCP and ExxonMobil	SFPP
FERC Docket No. IS07-234	BP WCP and ExxonMobil	Calnev
FERC Docket No. IS08-28	ConocoPhillips; Chevron; BP WCP; ExxonMobil ; Southwest Airlines; Western; and Valero	SFPP
FERC Docket No. IS08-302	Chevron; BP WCP; ExxonMobil; and Tesoro	SFPP
FERC Docket No. IS08-389	ConocoPhillips; Valero; Southwest Airlines Co.; Navajo; and Western	SFPP
FERC Docket No. IS08-390	BP WCP; ExxonMobil; ConocoPhillips; Valero; Chevron; and the Airlines	SFPP
Motions to compel payment of interim damages (various dockets)	Shippers	SFPP; Kinder Morgan G.P., Inc.; and Kinder Morgan, Inc.
Motion for resolution on the merits (various dockets)	BP WCP and ExxonMobil	SFPP and Calnev.

In this note, we refer to SFPP, L.P. as SFPP; Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as ConocoPhillips; Ultramar Diamond Shamrock Corporation/Ultramar Inc. as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airline Complainants; and the Federal Energy Regulatory Commission, as FERC.

The tariffs and rates charged by SFPP and Calnev (Kinder Morgan Energy Partners subsidiaries) are subject to numerous ongoing proceedings at the FERC, including the above listed shippers’ complaints and protests regarding interstate rates on these pipeline systems. These complaints have been filed over numerous years beginning in 1992 through and including 2008. In general, these complaints allege the rates and tariffs charged by SFPP and Calnev are not just and reasonable. If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaint) or refunds of any excess rates paid, and SFPP and Calnev may be required to reduce their rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. 

As to SFPP, the issues involved in these proceedings include, among others: (i) whether certain of SFPP operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance it may include in its rates. The issues involving Calnev are similar.

In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis; consequently, the level of income tax allowance to which SFPP will ultimately be entitled is not certain. In May of 2007, the D.C. Court upheld the FERC’s tax allowance policy.

In December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs. In accordance with the FERC’s December 2005 order and its February 2006 order on rehearing, SFPP submitted a compliance filing to the FERC in March 2006, and rate reductions were implemented on May 1, 2006. In

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addition, in December 2005, Kinder Morgan Energy Partners recorded accruals of $105.0 million for expenses attributable to an increase in its reserves related to its rate case liability.

In December 2007, as a follow-up to a March 2006 SFPP compliance filing to FERC, SFPP received a FERC order that directed Kinder Morgan Energy Partners to submit revised compliance filings and revised tariffs. In conjunction with FERC’s December 2007 order, Kinder Morgan Energy Partners’ other FERC and CPUC rate cases, and other unrelated litigation matters, it increased its litigation reserves by $140.0 million in the fourth quarter of 2007. And, in accordance with FERC’s December 2007 order and its February 2008 order on rehearing, SFPP submitted a compliance filing to FERC in February 2008, and further rate reductions were implemented on March 1, 2008.

During 2008, SFPP and Calnev made combined settlement payments to various shippers totaling approximately $30 million. In October 2008 in connection with OR92-8-025, IS6-283 and OR07-5, SFPP entered into a settlement resolving disputes regarding its East Line rates filed in Docket No. IS08-28 and related dockets. In January 2009, the FERC approved the settlement. Upon the finality of FERC’s approval, reduced settlement rates are expected to go into effect on May 1, 2009, and SFPP will make refunds and settlement payments shortly thereafter estimated to total approximately $16.0 million.

Based on our review of these FERC proceedings, we estimate that as of December 31, 2008, shippers are seeking approximately $355 million in reparation and refund payments and approximately $30 to $35 million in additional annual rate reductions. We assume that, with respect to our SFPP litigation reserves, any reparations and accrued interest thereon will be paid no earlier than the second quarter of 2009.

California Public Utilities Commission Proceedings

On April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission, referred to in this note as the CPUC. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and requests prospective rate adjustments and refunds with respect to previously untariffed charges for certain pipeline transportation and related services.

In October 2002, the CPUC issued a resolution, referred to in this note as the Power Surcharge Resolution, approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution reserves the right to require refunds from the date of issuance of the resolution to the extent the CPUC’s analysis of cost data to be submitted by SFPP demonstrates that SFPP’s California jurisdictional rates are unreasonable in any fashion.

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

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

All of the above matters have been consolidated and assigned to a single administrative law judge. At the time of this report, it is unknown when a decision from the CPUC regarding the CPUC complaints and the Power Surcharge Resolution will be received. No schedule has been established for hearing and resolution of the consolidated proceedings other than the 1997 CPUC complaint and the Power Surcharge Resolution. Based on our review of these CPUC proceedings, we estimate that shippers are seeking approximately $100 million in reparation and refund payments and approximately $35 million in annual rate reductions.

On June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed separate general rate case applications, neither of which request a change in existing pipeline rates and both of which assert that existing pipeline rates are reasonable. On September 26, 2008, SFPP filed an amendment to its general rate case application, requesting CPUC approval of a $5 million rate increase for intrastate transportation services that became effective November 1, 2008. Protests to the amended rate increase application have been filed by various shippers and, as a consequence, the related rate increase is being collected subject to refund. The CPUC has issued a ruling suspending further activity with respect to the SFPP and Calnev Pipe Line Company general rate case applications, pending CPUC resolution of the 1997 CPUC complaint and Power Surcharge proceedings. Consequently, no action has been taken by the CPUC with respect to either the SFPP amended general rate case filing or the Calnev general rate case filing.

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Carbon Dioxide Litigation

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

Kinder Morgan CO2 Company, L.P. (referred to in this note as 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. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. have also asserted claims as private relators under the False Claims Act and for violation of federal and Colorado antitrust laws. The plaintiffs seek actual damages, treble damages, punitive damages, a constructive trust and accounting, and declaratory relief. The defendants filed motions for summary judgment on all claims.

Effective March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final settlement agreement which provides for the dismissal of these plaintiffs’ claims with prejudice to being refiled. On June 10, 2007, the Houston federal district court entered an order of partial dismissal by which the claims by and against the settling plaintiffs were dismissed with prejudice. The claims asserted by Bailey, Ptasynski, and Gray are not included within the settlement or the order of partial dismissal. Effective April 8, 2008, the Shell and Kinder Morgan defendants and plaintiff Gray entered into an indemnification agreement that provides for the dismissal of Gray’s claims with prejudice.

On April 22, 2008, the federal district court granted defendants’ motions for summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take nothing on their claims. The court entered final judgment in favor of defendants on April 30, 2008. Defendants have filed a motion seeking sanctions against plaintiff Bailey. The plaintiffs have appealed the final judgment to the United States Fifth Circuit Court of Appeals. In October 2008, plaintiffs filed their brief in the Fifth Circuit Court of Appeals. Defendants filed their brief in the Fifth Circuit in December 2008.

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 alleged that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $12 million. The plaintiff also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million. On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement. On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.

On October 2, 2007, the plaintiff initiated a second arbitration (CO2 Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil entity. The second arbitration asserts claims similar to those asserted in the first arbitration. On June 3, 2008, the plaintiff filed a request with the American Arbitration Association seeking administration of the arbitration. In October 2008, the New Mexico federal district court entered an order declaring that the panel in the first arbitration should decide whether the claims in the second arbitration are barred by res judicata. The plaintiff filed a motion for reconsideration of that order, which was denied by the New Mexico federal district court in January 2009. Plaintiff has appealed to the Tenth Circuit Court of Appeals and continues to seek administration of the second arbitration by the American Arbitration Association.

MMS Notice of Noncompliance and Civil Penalty

On December 20, 2006, Kinder Morgan CO2 received a “Notice of Noncompliance and Civil Penalty: Knowing or Willful Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company, L.P., Case No. CP07-001” from the U.S. Department of the Interior, Minerals Management Service, referred to in this note as the MMS. This Notice, and the MMS’s position that Kinder Morgan CO2 has violated certain reporting obligations, relates to a disagreement between the MMS and Kinder Morgan CO2 concerning the approved transportation allowance to be used in valuing McElmo Dome carbon dioxide for purposes of calculating federal royalties. The Notice of Noncompliance and Civil Penalty assesses a

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civil penalty of approximately $2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2’s alleged submission of false, inaccurate, or misleading information relating to the transportation allowance, and federal royalties for CO2 produced at McElmo Dome, during the period from June 2005 through October 2006. The MMS stated that civil penalties will continue to accrue at the same rate until the alleged violations are corrected.

The parties have reached a settlement of the Notice of Noncompliance and Civil Penalty. The settlement agreement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments by Shell CO2 General LLC and Shell CO2 LLC pursuant to a royalty claim indemnification agreement.

MMS Order to Report and Pay

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

In addition to the March 2007 Order to Report and Pay, in April 2007, Kinder Morgan CO2 received an “Audit Issue Letter” sent by the Colorado Department of Revenue on behalf of the U.S. Department of the Interior. In the letter, the Department of Revenue states that Kinder Morgan CO2 has over-reported transportation allowances and underpaid royalties (due to the use of the Cortez Pipeline Company tariff as the transportation allowance for purposes of federal royalties) in the amount of $8.5 million for the period from April 2000 through December 2004.

The MMS and Kinder Morgan CO2 reached a settlement of the March 2007 and August 2007 Orders to Report and Pay. The settlement agreement is subject to final MMS approval. The settlement is subject to final MMS approval and upon approval will be funded from existing reserves and indemnity payments from Shell CO2 General LLC and Shell CO2 LLC pursuant to a royalty claim indemnification agreement.

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

This case involves a purported class action against Kinder Morgan CO2 alleging that it has failed to pay the full royalty and overriding royalty (“royalty interests”) on the true and proper settlement value of compressed carbon dioxide produced from the Bravo Dome Unit during the period beginning January 1, 2000. The complaint purports to assert claims for violation of the New Mexico Unfair Practices Act, constructive fraud, breach of contract and of the covenant of good faith and fair dealing, breach of the implied covenant to market, and claims for an accounting, unjust enrichment, and injunctive relief. The purported class is comprised of current and former owners, during the period January 2000 to the present, who have private property royalty interests burdening the oil and gas leases held by the defendant, excluding the Commissioner of Public Lands, the United States of America, and those private royalty interests that are not unitized as part of the Bravo Dome Unit.

The case was tried in the trial court in September 2008. The plaintiffs sought $6.8 million in actual damages as well as punitive damages. The jury returned a verdict finding that Kinder Morgan did not breach the settlement agreement and did not breach the claimed duty to market carbon dioxide. The jury also found that Kinder Morgan breached a duty of good faith and fair dealing and found compensatory damages of $0.3 million and punitive damages of $1.2 million. On October 16, 2008, the trial court entered judgment on the verdict.

On January 6, 2009, the district court entered orders vacating the judgment and granting a new trial in the case, which is scheduled a new trial to occur beginning on October 19, 2009.

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

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Commercial Litigation Matters

Union Pacific Railroad Company Easements

SFPP and Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company and referred to in this note as UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way. The trial is ongoing and is expected to conclude in the second quarter of 2009.

SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP has appealed this decision and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that it has complete discretion to cause the pipeline to be relocated at SFPP’s expense at any time and for any reason, and that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards. Each party is seeking declaratory relief with respect to its positions regarding relocations.

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

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

This multi-district litigation proceeding involves four lawsuits filed in 1997 against numerous Kinder Morgan companies. These suits were filed pursuant to the federal False Claims Act and allege underpayment of royalties due to mismeasurement of natural gas produced from federal and Indian lands. The complaints are part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants) in various courts throughout the country that were consolidated and transferred to the District of Wyoming.

In May 2005, a Special Master appointed in this litigation found that because there was a prior public disclosure of the allegations and that Grynberg was not an original source, the Court lacked subject matter jurisdiction. As a result, the Special Master recommended that the Court dismiss all the Kinder Morgan defendants. In October 2006, the United States District Court for the District of Wyoming upheld the dismissal of each case against the Kinder Morgan defendants on jurisdictional grounds. Grynberg has appealed this Order to the Tenth Circuit Court of Appeals. Briefing was completed and oral argument was held on September 25, 2008. No decision has yet been issued.

Prior to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without evidentiary support and for an improper purpose. On January 8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a Motion for Attorney Fees under the False Claim Act. On April 24, 2007, the Court held a hearing on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees. A decision is still pending on the Motions to Dismiss and for Sanctions and the Requests for Attorney Fees.

Leukemia Cluster Litigation

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

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

On May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil action in the Nevada State trial court against Kinder Morgan Energy Partners 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

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wrongful death, premises liability, negligence, negligence per se, intentional infliction of emotional distress, negligent infliction of emotional distress, assault and battery, nuisance, fraud, strict liability (ultra hazardous acts), and aiding and abetting, and seek unspecified special, general and punitive damages. On August 28, 2003, a separate group of plaintiffs, represented by the counsel for the plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court against the same defendants and alleging the same claims as in the Jernee case with respect to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial purposes with the Sands case. In May 2006, the court granted defendants’ motions to dismiss as to the counts purporting to assert claims for fraud, but denied defendants’ motions to dismiss as to the remaining counts, as well as defendants’ motions to strike portions of the complaint. Defendant Kennametal, Inc. has filed a third-party complaint naming the United States and the United States Navy (the “United States”) as additional defendants. In response, the United States removed the case to the United States District Court for the District of Nevada and filed a motion to dismiss the third-party complaint. Plaintiff has also filed a motion to dismiss the United States and/or to remand the case back to state court. By order dated September 25, 2007, the United States District Court granted the motion to dismiss the United States from the case and remanded the Jernee and Sands cases back to the Second Judicial District Court, State of Nevada, County of Washoe. The cases will now proceed in the State Court. Based on the information available to date, our own preliminary investigation, and the positive results of investigations conducted by State and Federal agencies, we believe that the remaining claims against Kinder Morgan Energy Partners in these matters are without merit and intend to defend against them vigorously.

Pipeline Integrity and Releases

From time to time, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Pasadena Terminal Fire

On September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena, Texas terminal facility. One of our employees was injured and subsequently died. In addition, the pit 3 manifold was severely damaged. The cause of the incident is currently under investigation by the Railroad Commission of Texas and the United States Occupational Safety and Health Administration. The remainder of the facility returned to normal operations within twenty-four hours of the incident.

Walnut Creek, California Pipeline Rupture

On November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a third-party contractor on a water main installation project hired by East Bay Municipal Utility District, struck and ruptured an underground petroleum pipeline owned and operated by SFPP 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, Inc. Following court ordered mediation, we have settled with plaintiffs in all of the wrongful death cases and the personal injury and property damages cases. On January 12, 2009, the Contra Costa Superior Court granted summary judgment in favor of Kinder Morgan G.P. Services Co., Inc. in the last remaining civil suit – a claim for indemnity brought by co-defendant Camp, Dresser & McKee, Inc. The only remaining pending matter is our appeal of a civil fine of $140,000 issued by the California Division of Occupational Safety and Health.

Rockies Express Pipeline LLC Wyoming Construction Incident

On November 11, 2006, a bulldozer operated by an employee of Associated Pipeline Contractors, Inc., (a third-party contractor to Rockies Express Pipeline LLC, referred to in this note as REX), struck an existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group. The pipeline was ruptured, resulting in an explosion and fire. The incident occurred in a rural area approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted in one fatality (the operator of the bulldozer) and there were no other reported injuries. The cause of the incident was investigated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, referred to in this report as the PHMSA. In March 2008, the PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (“NOPV”) to El Paso Corporation in which it concluded that El Paso failed to comply with federal law and its internal policies and procedures regarding protection of its pipeline, resulting in this incident. To date, the PHMSA has not issued any NOPV’s to REX, and we do not expect that it will do so. Immediately following the incident, REX and El Paso Pipeline Group reached an agreement on a set of additional enhanced safety protocols designed to prevent the reoccurrence of such an incident.

In September 2007, the family of the deceased bulldozer operator filed a wrongful death action against Kinder Morgan Energy Partners, REX and several other parties in the District Court of Harris County, Texas, 189th Judicial District, at case number 2007-57916. The plaintiffs seek unspecified compensatory and exemplary damages plus interest, attorney’s fees and

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costs of suit. Kinder Morgan Energy Partners has asserted contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers. On March 25, 2008, the defendants entered into a settlement agreement with one of the plaintiffs, the decedent’s daughter, resolving any and all of her claims against Kinder Morgan Energy Partners, REX and its contractors. Kinder Morgan Energy Partners was indemnified for the full amount of this settlement by one of REX’s contractors.  On October 17, 2008, the remaining plaintiffs filed a Notice of Nonsuit, which dismissed the remaining claims against all defendants without prejudice to the plaintiffs’ ability to re-file their claims at a later date. The remaining plaintiffs re-filed their Complaint against REX, Kinder Morgan Energy Partners and several other parties on November 7, 2008, Cause No. 2008-66788, currently pending in the District Court of Harris County, Texas, 189th Judicial District. The parties are currently engaged in discovery.

Charlotte, North Carolina

On November 27, 2006, the Plantation Pipeline experienced a release of approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company block valve on a delivery line into a terminal owned by a third party company. The line was repaired and put back into service within a few days. Remediation efforts are continuing under the direction of the North Carolina Department of Environment and Natural Resources (the “NCDENR”), which issued a Notice of Violation and Recommendation of Enforcement against Plantation on January 8, 2007. Plantation continues to cooperate fully with the NCDENR.

Although Plantation does not believe that penalties are warranted, it has engaged in settlement discussions with the EPA regarding a potential civil penalty for the November 2006 release as part of broader settlement negotiations with the EPA regarding this spill and three other historic releases from Plantation, including a February 2003 release near Hull, Georgia. Plantation has entered into a consent decree with the Department of Justice and the EPA for all four releases for approximately $0.7 million, plus some additional work to be performed to prevent future releases. The proposed consent decree was filed in U.S. District Court and is awaiting entry by the court.

In addition, in April 2007, during pipeline maintenance activities near Charlotte, North Carolina, Plantation discovered the presence of historical soil contamination near the pipeline, and reported the presence of impacted soils to the NCDENR. Subsequently, Plantation contacted the owner of the property to request access to the property to investigate the potential contamination. The results of that investigation indicate that there is soil and groundwater contamination, which appears to be from an historical turbine fuel release. The groundwater contamination is underneath at least two lots on which there is current construction of single-family homes as part of a new residential development. Further investigation and remediation are being conducted under the oversight of the NCDENR. Plantation reached a settlement with the builder of the residential subdivision. Plantation continues to negotiate with the owner of the property to address any potential claims that it may bring.

Barstow, California

The United States Department of Navy has alleged that historic releases of methyl tertiary-butyl ether, referred to in this report as MTBE, from Calnev’s Barstow terminal has (i) migrated underneath the Navy’s Marine Corps Logistics Base (the “MCLB”) in Barstow, (ii) impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev, and (iii) affected the MCLB’s water supply system. Although Calnev believes that it has certain meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for CERCLA Removal Action to reimburse the Navy for $0.5 million in past response actions, plus perform other work to ensure protection of the Navy’s existing treatment system and water supply.

Oil Spill Near Westridge Terminal, Burnaby, British Columbia

On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within Kinder Morgan Energy Partners’ Trans Mountain pipeline system near its Westridge terminal in Burnaby, BC, resulting in a release of approximately 1,400 barrels of crude oil. The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet. No injuries were reported. To address the release, Kinder Morgan Energy Partners initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the BC Ministry of Environment, the National Energy Board, and the National Transportation Safety Board. Cleanup and environmental remediation is near completion. The incident is currently under investigation by Federal and Provincial agencies. We do not expect this matter to have a material adverse impact on our financial position, results of operations or cash flows.

On December 20, 2007, Kinder Morgan Energy Partners initiated a lawsuit entitled Trans Mountain Pipeline LP, Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No. S078716. The suit alleges that the City of Burnaby and its agents are liable for damages including, but not limited to, all costs and expenses incurred by Kinder Morgan Energy Partners as a result of the rupture of the pipeline and subsequent release of crude oil. Defendants have denied liability and discovery has begun.

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Litigation Relating to the “Going Private” Transaction

Beginning on May 29, 2006, the day after the proposal for the Going Private transaction was announced, and in the days following, eight putative Class Action lawsuits were filed in Harris County (Houston), Texas and seven putative Class Action lawsuits were filed in Shawnee County (Topeka), Kansas against, among others, Kinder Morgan, Inc., its Board of Directors, the Special Committee of the Board of Directors, and several corporate officers.

By order of the Harris County District Court dated June 26, 2006, each of the eight Harris County cases were consolidated into the Crescente v. Kinder Morgan, Inc. et al case, Cause No. 2006-33011, in the 164th Judicial District Court, Harris County, Texas, which challenges the proposed transaction as inadequate and unfair to Kinder Morgan, Inc.’s public stockholders. On September 8, 2006, interim class counsel filed their Consolidated Petition for Breach of Fiduciary Duty and Aiding and Abetting in which they alleged that Kinder Morgan, Inc.’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the merger, rescission of the merger agreement, disgorgement of any improper profits received by the defendants, and attorneys’ fees. Defendants filed Answers to the Consolidated Petition on October 9, 2006, denying the plaintiffs’ substantive allegations and denying that the plaintiffs are entitled to relief.

By order of the District Court of Shawnee County, Kansas dated June 26, 2006, each of the seven Kansas cases were consolidated into the Consol. Case No. 06 C 801; In Re Kinder Morgan, Inc. Shareholder Litigation; in the District Court of Shawnee County, Kansas, Division 12. On August 28, 2006, the plaintiffs filed their Consolidated and Amended Class Action Petition in which they alleged that Kinder Morgan’s board of directors and certain members of senior management breached their fiduciary duties and the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty in entering into the merger agreement. They sought, among other things, to enjoin the stockholder vote on the merger agreement and any action taken to effect the acquisition of Kinder Morgan and its assets by the buyout group, damages, disgorgement of any improper profits received by the defendants, and attorney’s fees.

In late 2006, the Kansas and Texas Courts appointed the Honorable Joseph T. Walsh to serve as Special Master in both consolidated cases “to control all of the pretrial proceedings in both the Kansas and Texas Class Actions arising out of the proposed private offer to purchase the stock of the public shareholders of Kinder Morgan, Inc.” On November 21, 2006, the plaintiffs in In Re Kinder Morgan, Inc. Shareholder Litigation filed a Third Amended Class Action Petition with Special Master Walsh. This Petition was later filed under seal with the Kansas District Court on December 27, 2006.

Following extensive expedited discovery, the Plaintiffs in both consolidated actions filed an application for a preliminary injunction to prevent the holding of a special meeting of shareholders for the purposes of voting on the proposed merger, which was scheduled for December 19, 2006.

On December 18, 2006, Special Master Walsh issued a Report and Recommendation concluding, among other things, that “plaintiffs have failed to demonstrate the probability of ultimate success on the merits of their claims in this joint litigation.” Accordingly, the Special Master concluded that the plaintiffs were “not entitled to injunctive relief to prevent the holding of the special meeting of KMI shareholders scheduled for December 19, 2006.”

Plaintiffs moved for class certification in January, 2008. Defendants opposed this motion, which is currently pending.

On January 9, 2009, Special Master Walsh issued a Report recommending that the class should be comprised ofall holders of Kinder Morgan, Inc. common stock, during the period August 28, 2006 (the date the merger agreement was signed) through May 30, 2007 (the date the merger closed) and their transferees, successors and assigns. Excluded from the Class are defendants and any person, firm, trust, corporation or other entity related to or affiliated with any defendant. Special Master Walsh also recommended that Dr. Geiger and Mr. Wilson, but not Mr. Land, be appointed as Class Representatives. The Special Master’s recommendation is currently pending before the Kansas trial court.

In August, September and October, 2008, the Plaintiffs in both consolidated cases voluntarily dismissed without prejudice the claims against those Kinder Morgan, Inc.’s directors who did not participate in the buyout (including the dismissal of the members of the special committee of the board of directors), Kinder Morgan, Inc. and Knight Acquisition, Inc. In addition, on November 19, 2008, by agreement of the parties, the Texas trial court issued an order staying all proceedings in the Texas actions until such time as a final judgment shall be issued in the Kansas actions. The effect of this stay is that the consolidated matters will proceed only in the Kansas trial court.

The parties are currently engaged in consolidated discovery in these matters.

On August 24, 2006, a civil action entitled City of Inkster Policeman and Fireman Retirement System, Derivatively on Behalf of Kinder Morgan, Inc., Plaintiffs v. Richard D. Kinder, Michael C. Morgan, William v. Morgan, Fayez Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W. Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward

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Randall, III, Douglas W.G. Whitehead, Goldman Sachs Capital Partners, American International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park Shaper, Steven J. Kean, Scott E. Parker and R. Tim Bradley, Defendants and Kinder Morgan, Inc., Nominal Defendant; Case 2006-52653, was filed in the 270th Judicial District Court, Harris County, Texas. This putative derivative lawsuit was brought against certain of Kinder Morgan, Inc.’s senior officers and directors, alleging that the proposal constituted a breach of fiduciary duties owed to Kinder Morgan, Inc. Plaintiff also contends that the Sponsor Investors aided and abetted the alleged breaches of fiduciary duty. Plaintiff seeks, among other things, to enjoin the defendants from consummating the proposal, a declaration that the proposal is unlawful and unenforceable, the imposition of a constructive trust upon any benefits improperly received by the defendants, and attorney’s fees. In November 2007, defendants filed a Joint Motion to Dismiss for Lack of Jurisdiction, or in the Alternative, Motion for Final Summary Judgment. Plaintiffs opposed the motion. In February 2008, the court entered a Final Order granting defendants’ motion in full, ordering that plaintiff, the City of Inkster Policeman and Fireman Retirement System, take nothing on any and all of its claims against any and all defendants. In April 2008, Plaintiffs filed an appeal of the judgment in favor of all defendants in the Texas Court of Appeal, First District. The appeal is currently pending.

Defendants believe that the claims asserted in the litigations regarding the Going Private transaction are legally and factually without merit and intend to vigorously defend against them.

Litigation Reserves

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.

Additionally, although it is not possible to predict the ultimate outcomes, we believe, based on our experiences to date, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or cash flows. As of December 31, 2008 and December 31, 2007, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $234.8 million and $249.4 million, respectively. The reserve is primarily related to various claims from lawsuits related to SFPP and the contingent amount is based on both probability of realization and our ability to reasonably estimate liability dollar amounts. We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

Environmental Matters

ExxonMobil Corporation v. GATX Terminals Corporation, Kinder Morgan Liquids Terminals LLC and Support Terminals Services, Inc.

On April 23, 2003, Exxon Mobil Corporation (“ExxonMobil”) filed a complaint in the Superior Court of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation (“GATX”). from 1989 through September 2000, later owned by Support Terminals Services, Inc. (“Support Terminals”). The terminal is now owned by Pacific Atlantic Terminals, LLC, (PAT) and it too is a party to the lawsuit.

The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit. The parties are currently involved in mandatory mediation and met in June and October 2008. No progress was made at any of the mediations. The mediation judge will now refer the case back to the litigation court room.

On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil and Kinder Morgan Liquids Terminals LLC, f/k/a GATX. The complaint was filed in Gloucester County, New Jersey. Both ExxonMobil and Kinder Morgan Liquids Terminals LLC filed third party complaints against Support Terminals seeking to bring Support Terminals into the case. Support Terminals filed motions to dismiss the third party complaints, which were denied. Support Terminals is now joined in the case and it filed an Answer denying all claims.

The plaintiffs seek the costs and damages that the plaintiffs allegedly have incurred or will incur as a result of the discharge of pollutants and hazardous substances at the Paulsboro, New Jersey facility. The costs and damages that the plaintiffs seek include cleanup costs and damages to natural resources. In addition, the plaintiffs seek an order compelling the defendants to perform or fund the assessment and restoration of those natural resource damages that are the result of the defendants’ actions. As in the case brought by ExxonMobil against GATX, the issue is whether the plaintiffs’ claims are within the scope of the indemnity obligations between GATX (and therefore, Kinder Morgan Liquids Terminals LLC) and Support Terminals. The court may consolidate the two cases.

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Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the state of California, filed a lawsuit against Kinder Morgan Energy Partners and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the city’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, Kinder Morgan Energy Partners removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB. On October 3, 2007, Kinder Morgan Energy Partners filed a Motion to Dismiss all counts of the Complaint. The court denied in part and granted in part the Motion to Dismiss and gave the City leave to amend their complaint. The City submitted its Amended Complaint and we filed an Answer. The parties have commenced with discovery. This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.

In June 2008, we received an Administrative Civil Liability Complaint from the California Regional Water Quality Control Board for violations and penalties associated with permitted surface water discharge from the remediation system operating at the Mission Valley terminal facility. In December 2008, we settled the Administrative Civil Liability Complaint with the RWQCB, paying a civil penalty of $0.2 million.

State of Texas v. Kinder Morgan Petcoke, L.P.

Harris County, Texas Criminal Court No. 11, Cause No. 1571148. On February 24, 2009 a subsidiary of Kinder Morgan Energy Partners, Kinder Morgan Petcoke, L.P., was served with a misdemeanor summons alleging the unintentional discharge of petcoke into the Houston Ship Channel during maintenance activities. The maximum potential fine for the alleged violation is $0.2 million. The allegations in the summons are currently under investigation.

Other Environmental

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

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

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

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

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual settlements of these claims will occur and changing circumstances could cause these matters to have a material adverse impact. As of December 31, 2008 and December 31, 2007, we have accrued an environmental reserve of$85.0 million and $102.6 million, respectively, and we believe the establishment of this environmental reserve is adequate such that the resolution of pending environmental matters

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will not have a material adverse impact on our business, cash flows, financial position or results of operation. 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. Associated with the environmental reserve, we have recorded a receivable of $20.9 million as of both December 31, 2008 and December 31, 2007 for expected cost recoveries that have been deemed probable.

22. Recent Accounting Pronouncements

SFAS No. 157 and associated pronouncements

For information on SFAS No. 157 and associated pronouncements, see Note 15 under the heading “SFAS No. 157.”

SFAS No. 159

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

SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. It also requires entities to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. The Statement does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157, discussed in Note 15, “SFAS No. 157,” and SFAS No. 107 Disclosures about Fair Value of Financial Instruments.

This Statement was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our consolidated financial statements.

SFAS No. 141(R)

On December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), Business Combinations. Although this Statement amends and replaces SFAS No. 141, it retains the fundamental requirements in SFAS No. 141 that (i) the purchase method of accounting be used for all business combinations and (ii) an acquirer be identified for each business combination. SFAS No. 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control.

Significant provisions of SFAS No. 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for us). The adoption of this Statement did not have any impact on our consolidated financial statements.

SFAS No. 160

For information on SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements, see Note 1.

SFAS No. 161

On March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. This Statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and is intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows through enhanced disclosure requirements. The enhanced disclosures include, among other things, (i) a tabular summary of the fair value of derivative instruments and their gains and losses, (ii) disclosure of derivative

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features that are credit-risk–related to provide more information regarding an entity’s liquidity and (iii) cross-referencing within footnotes to make it easier for financial statement users to locate important information about derivative instruments.

This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). This Statement expands and enhances disclosure requirements only, and as such, the adoption of this Statement did not have any impact on our consolidated financial statements.

FSP No. FAS 142-3

On April 25, 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The adoption of this FSP did not have a material impact on our consolidated financial statements.

SFAS No. 162

On May 9, 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This Statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities.

SFAS No. 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the U.S. Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles, and is only effective for nongovernmental entities. We expect the adoption of this Statement will have no effect on our consolidated financial statements.

EITF 08-6

On November 24, 2008, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 08-6, or EITF 08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies certain accounting and impairment considerations involving equity method investments. This Issue is effective for fiscal years beginning on or after December 15, 2008 (January 1, 2009 for us), and interim periods within those fiscal years. The guidance in this Issue is to be applied prospectively for all financial statements presented. The adoption of this Issue did not have any impact on our consolidated financial statements.

FSP No. FAS 140-4 and FIN 46(R)-8

On December 11, 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities. These two pronouncements require enhanced disclosure and transparency by public entities about their involvement with variable interest entities and their continuing involvement with transferred financial assets. The disclosure requirements in these two pronouncements are effective for annual and interim periods ending after December 15, 2008 (December 31, 2008 for us). The adoption of these two pronouncements did not have any impact on our consolidated financial statements.

FSP No. FAS 132(R)-1

On December 30, 2008, the FASB issued FSP No. FAS 132(R)-1, Employer’s Disclosures About Postretirement Benefit Plan Assets, effective for financial statements ending after December 15, 2009 (December 31, 2009 for us). This FSP requires additional disclosure of pension and postretirement plan holdings regarding (i) investment asset classes, (ii) fair value measurement of assets, (iii) investment strategies, (iv) asset risk and (v) rate-of-return assumptions. We do not expect this FSP to have a material impact on our consolidated financial statements.

Securities and Exchange Commission’s Final Rule on Oil and Gas Disclosure Requirements

On December 31, 2008, the Securities and Exchange Commission (“SEC”) issued its final rule, Modernization of Oil and Gas Reporting, which revises the disclosures required by oil and gas companies. The SEC disclosure requirements for oil and gas companies have been updated to include expanded disclosure for oil and gas activities, and certain definitions have also been changed that will impact the determination of oil and gas reserve quantities. The provisions of this final rule are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. We are currently reviewing the effects of this SEC final rule.

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23. Subsequent Events

On February 2, 2009, Kinder Morgan Energy Partners paid $250 million to retire the principal amount of its 6.30% senior notes that matured on that date.

In February and March 2009, Kinder Morgan Energy Partners sold 5,666,000 of its common units in a public offering at a price of $46.95 per unit. Kinder Morgan Energy Partners received net proceeds, after commissions and underwriting expenses, of approximately $260 million for the issuance of these 5,666,000 common units and used the proceeds to reduce the borrowings under its bank credit facility.

On February 25, 2009, Kinder Morgan Energy Partners entered into four additional fixed-to-floating interest rate swap agreements having a combined notional principal amount of $1.0 billion related to (i) $200 million 6.00% senior notes due 2017, (ii) $300 million of 5.125% senior notes due 2014, (iii) $25 million 5.00% senior notes due 2013 and (iv) $475 million of 5.95% senior notes due 2018.

Events Subsequent to March 31, 2009 (Unaudited)

As further discussed in Note 1, on July 15, 2009 the Company’s name reverted to Kinder Morgan, Inc.

Selected Quarterly Financial Data (Unaudited)

Quarterly Operating Results for 2008 and 2007

	Successor Company
	Three Months Ended
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008
	(In millions)
Operating Revenues	$	2,895.0		$	3,560.5		$	3,296.6		$	2,342.7
Gas Purchases and Other Costs of Sales		1,760.6			2,494.1			2,179.2			1,310.1
Other Operating Expenses		658.2			4,704.5			719.1			741.1
Operating Income (Loss)		476.2			(3,638.1	)		398.3			291.5
Other Income and (Expenses)		(157.1	)		(76.4	)		(94.7	)		(97.7	)
Income (Loss) from Continuing Operations Before Income Taxes		319.1			(3,714.5	)		303.6			193.8
Income Taxes		87.1			19.4			87.9			109.9
Income (Loss) from Continuing Operations		232.0			(3,733.9	)		215.7			83.9
Income (Loss) from Discontinued Operations, Net of Tax		(0.1	)		(0.3	)		(0.2	)		(0.3	)
Net Income (Loss)		231.9			(3,734.2	)		215.5			83.6
Net Income Attributable to Noncontrolling Interests		(126.2	)		(126.4	)		(106.8	)		(36.7	)
Net Income (Loss) Attributable to Kinder Morgan, Inc.’s Stockholder	$	105.7		$	(3,860.6	)	$	108.7		$	46.9

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	Predecessor Company						Successor Company
	Three Months Ended				Two Months Ended		One Month Ended				Three Months Ended
	March 31, 2007				May 31, 2007		June 30, 2007				September 30, 2007			December 31, 2007
	(In millions)						(In millions)
Operating Revenues	$	2,444.4		$	1,720.7		$	936.9		$	2,609.0		$	2,848.8
Gas Purchases and Other Costs of Sales		1,452.5			1,037.9			557.2			1,482.8			1,616.6
Other Operating Expenses		968.0			501.9			220.5			683.2			791.6
Operating Income		23.9			180.9			159.2			443.0			440.6
Other Income and (Expenses)		(123.6	)		(87.7	)		(75.5	)		(225.9	)		(227.9	)
Income (Loss) from Continuing Operations Before Income Taxes		(99.7	)		93.2			83.7			217.1			212.7
Income Taxes		87.7			47.8			21.3			74.6			131.5
Income (Loss) from Continuing Operations		(187.4	)		45.4			62.4			142.5			81.2
Income (Loss) from Discontinued Operations, Net of Tax		233.2			65.4			2.3			(4.4	)		0.6
Net Income		45.8			110.8			64.7			138.1			81.8
Net Loss (Income) Attributable to Noncontrolling Interests		(58.2	)		(32.5	)		(34.5	)		(52.4	)		49.3
Net Income (Loss) Attributable to Kinder Morgan, Inc.’s
Stockholder	$	(12.4	)	$	78.3		$	30.2		$	85.7		$	131.1

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Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The Supplementary Information on Oil and Gas Producing Activities is presented as required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The supplemental information includes capitalized costs related to oil and gas producing activities; costs incurred for the acquisition of oil and gas producing activities, exploration and development activities; and the results of operations from oil and gas producing activities.

Supplemental information is also provided for per unit production costs; oil and gas production and average sales prices; the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

Our capitalized costs consisted of the following:

Capitalized Costs Related to Oil and Gas Producing Activities

	Successor Company						Predecessor Company
	December 31,						December 31,
	2008			2007			2006
	(In millions)						(In millions)
Consolidated Companies1
Wells and equipment, facilities and other	$	2,595.4		$	2,081.3		$	1,369.5
Leasehold		429.8			449.3			347.4
Total proved oil and gas properties		3,025.2			2,530.6			1,716.9
Accumulated depreciation and depletion		(1,155.6	)		(787.6	)		(470.2	)
Net capitalized costs	$	1,869.6		$	1,743.0		$	1,246.7

__________

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

Includes capitalized asset retirement costs and associated accumulated depreciation. There are no capitalized costs associated with unproved oil and gas properties for the periods reported.

Our costs incurred for property acquisition, exploration and development were as follows:

Costs Incurred in Exploration, Property Acquisitions and Development

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Consolidated Companies1
Property Acquisition
Proved oil and gas properties	$	-	$	-	$	-	$	36.6
Development		495.2		156.9		87.5		261.8

__________

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

There are no capitalized costs associated with unproved oil and gas properties for the periods reported. All capital expenditures were made to develop our proved oil and gas properties and no exploration costs were incurred for the periods reported.

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Our results of operations from oil and gas producing activities for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006 are shown in the following table:

	Successor Company				Predecessor Company
	Year Ended December 31, 2008		Seven Months Ended December 31, 2007		Five Months Ended May 31, 2007		Year Ended December 31, 2006
	(In millions)				(In millions)
Consolidated Companies1
Revenues2	$	785.5	$	352.0	$	237.7		524.7
Expenses:
Production costs		308.4		147.2		96.7		208.9
Other operating expenses3		99.0		34.9		22.0		66.4
Depreciation, depletion and amortization expenses		342.2		151.9		106.6		169.4
Total expenses		749.6		334.0		225.3		444.7
Results of operations for oil and gas producing activities	$	35.9	$	18.0	$	12.4	$	80.0

__________

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

2 Revenues include losses attributable to our hedging contracts of $693.3 million, $311.5 million, $122.7 million and $441.7 million for the year ended December 31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007 and year ended December 31, 2006, respectively.

3 Consists primarily of carbon dioxide expense.

The table below represents estimates, as of December 31, 2008, of proved crude oil, natural gas liquids and natural gas reserves prepared by Netherland, Sewell and Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries’ interests in oil and gas properties, all of which are located in the state of Texas. This data has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this document. The estimates of reserves and future revenue in this document conforms to the guidelines of the United States Securities and Exchange Commission.

We believe the geologic and engineering data examined provides reasonable assurance that the proved reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are subject to change, either positively or negatively, as additional information becomes available and contractual and economic conditions change.

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

During 2008, we filed estimates of our oil and gas reserves for the year 2007 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this report exceeds 5%.

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Reserve Quantity Information

	Consolidated Companies
	Crude Oil (MBbls)		NGLs (MBbls)		Nat. Gas (MMcf)1
Proved developed and undeveloped reserves as of
December 31, 20052	21,567		2,884		327
December 31, 20063	123,978		10,333		291
Revisions of Previous Estimates3,4	10,361		2,784		1,077
Production3	(12,984	)	(2,005	)	(290	)
December 31, 20073	121,355		11,112		1,078
Revisions of Previous Estimates3,5	(29,536	)	(2,490	)	695
Production3	(13,240	)	(1,762	)	(499	)
December 31, 20083	78,579		6,860		1,274
Proved developed reserves as of
December 31, 20052	11,965		1,507		251
December 31, 20063	69,073		5,877		291
December 31, 20073	70,868		5,517		1,078
December 31, 20083	53,346		4,308		1,274

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

2 For the period presented, we accounted for Kinder Morgan Energy Partners under the equity method, therefore, amounts reflect our proportionate share of Kinder Morgan Energy Partners’ proved reserves.

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

4 Associated with an expansion of the carbon dioxide flood project area of the SACROC unit.

5 Predominately due to lower product prices used to determine reserve volumes.

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year-to-year are prepared in accordance with SFAS No. 69. The assumptions that underlie the computation of the standardized measure of discounted cash flows may be summarized as follows:

· the standardized measure includes our estimate of proved crude oil, natural gas liquids and natural gas reserves and projected future production volumes based upon year-end economic conditions;

· pricing is applied based upon year-end market prices adjusted for fixed or determinable contracts that are in existence at year-end;

· future development and production costs are determined based upon actual cost at year-end;

· the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

· a discount factor of 10% per year is applied annually to the future net cash flows.

Our standardized measure of discounted future net cash flows from proved reserves were as follows:

Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves

	December 31,						December 31,
	2008			2007			2006
	(In millions)						(In millions)
Consolidated Companies1
Future Cash Inflows from Production	$	3,498.0		$	12,099.5		$	7,534.7
Future Production Costs		(1,671.6	)		(3,536.2	)		(2,617.9	)
Future Development Costs2		(910.3	)		(1,919.2	)		(1,256.8	)
Undiscounted Future Net Cash Flows		916.1			6,644.1			3,660.0
10% Annual Discount		(257.7	)		(2,565.7	)		(1,452.2	)
Standardized Measure of Discounted Future Net Cash Flows	$	658.4		$	4,078.4		$	2,207.8

__________

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

2 Includes abandonment costs.

The following table represents our estimate of changes in the standardized measure of discounted future net cash flows from proved reserves:

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Changes in the Standardized Measure of Discounted Future Net Cash Flows From

Proved Oil and Gas Reserves

	Year Ended December 31,
	2008			2007			2006
	(In millions)
Consolidated Companies1
Present Value as of January	$	4,078.4		$	2,207.8			3,075.0
Changes During the Year
Revenues Less Production and Other Costs2		(1,012.4	)		(722.1	)		(690.0	)
Net Changes in Prices, Production and Other Costs2		(3,076.9	)		2,153.2			(123.0	)
Development Costs Incurred		495.2			244.5			261.8
Net Changes in Future Development Costs		231.1			(547.8	)		(446.0	)
Purchases of Reserves in Place		—			-			3.2
Revisions of Previous Quantity Estimates3		(417.1	)		510.8			(179.5	)
Accretion of Discount		392.9			198.1			307.4
Timing Differences and Other		(32.8	)		33.9			(1.1	)
Net Change For the Year		(3,420.0	)		1,870.6			(867.2	)
Present Value as of December 31	$	658.4		$	4,078.4		$	2,207.8

__________

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

2 Excludes the effect of losses attributable to our hedging contracts of $639.3 million, $434.2 million and $441.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

3 2008 revisions are predominantly due to lower product prices used to determine reserve volumes. 2007 revisions are associated with an expansion of the carbon dioxide flood project area for the SACROC unit. 2006 revisions are based on lower than expected recoveries from a section of the SACROC unit carbon dioxide flood project.

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