KINDER MORGAN ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware		76-0380342
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In Millions Except Per Unit Amounts)

(Unaudited)

		Three Months Ended March 31,
		2011				2010
Revenues
Natural gas sales		$	806.0			$	1,017.5
Services			784.4				738.5
Product sales and other			402.4				373.6
Total Revenues			1,992.8				2,129.6
Operating Costs, Expenses and Other
Gas purchases and other costs of sales			815.7				1,016.6
Operations and maintenance			308.6				452.9
Depreciation, depletion and amortization			221.8				227.3
General and administrative			189.2				101.1
Taxes, other than income taxes			48.6				45.1
Other expense (income)			(0.2	)			(1.3	)
Total Operating Costs, Expenses and Other			1,583.7				1,841.7
Operating Income			409.1				287.9
Other Income (Expense)
Earnings from equity investments			64.9				46.7
Amortization of excess cost of equity investments			(1.5	)			(1.4	)
Interest expense			(132.0	)			(117.0	)
Interest income			5.3				5.5
Other, net			1.6				6.7
Total Other Income (Expense)			(61.7	)			(59.5	)
Income Before Income Taxes			347.4				228.4
Income Taxes			(6.5	)			(1.0	)
Net Income			340.9				227.4
Net Income Attributable to Noncontrolling Interests			(3.1	)			(2.1	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.		$	337.8			$	225.3
Calculation of Limited Partners’ Interest in Net Income (Loss)
Attributable to Kinder Morgan Energy Partners, L.P.:
Net Income Attributable to Kinder Morgan Energy Partners, L.P.		$	337.8			$	225.3
Less: General Partner’s interest			(280.6	)			(249.2	)
Limited Partners’ Interest in Net Income (Loss)		$	57.2			$	(23.9	)
Limited Partners’ Net Income (Loss) per Unit		$	0.18			$	(0.08	)
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit			317.2				298.8
Per Unit Cash Distribution Declared		$	1.14			$	1.07

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

 

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Millions)

		March 31, 2011				December 31, 2010
		(Unaudited)
ASSETS
Current assets
Cash and cash equivalents		$	178.4			$	129.1
Restricted deposits			4.4				50.0
Accounts, notes and interest receivable, net			831.6				951.8
Inventories			93.0				92.0
Gas in underground storage			27.4				2.2
Fair value of derivative contracts			35.2				24.0
Other current assets			17.7				37.6
Total current assets			1,187.7				1,286.7
Property, plant and equipment, net			14,695.5				14,603.9
Investments			3,903.0				3,886.0
Notes receivable			117.9				115.0
Goodwill			1,229.4				1,233.6
Other intangibles, net			289.3				302.2
Fair value of derivative contracts			190.9				260.7
Deferred charges and other assets			179.6				173.0
Total Assets		$	21,793.3			$	21,861.1
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt		$	1,333.2			$	1,262.4
Cash book overdrafts			35.9				32.5
Accounts payable			588.2				630.9
Accrued interest			91.6				239.6
Accrued taxes			78.1				44.7
Deferred revenues			103.7				96.6
Fair value of derivative contracts			380.5				281.5
Accrued other current liabilities			165.0				176.0
Total current liabilities			2,776.2				2,764.2
Long-term liabilities and deferred credits
Long-term debt
Outstanding			10,415.6				10,277.4
Value of interest rate swaps			530.4				604.9
Total Long-term debt			10,946.0				10,882.3
Deferred income taxes			245.7				248.3
Fair value of derivative contracts			282.3				172.2
Other long-term liabilities and deferred credits			445.5				501.6
Total long-term liabilities and deferred credits			11,919.5				11,804.4
Total Liabilities			14,695.7				14,568.6
Commitments and contingencies (Notes 4 and 10)
Partners’ Capital
Common units			4,217.4				4,282.2
Class B units			59.6				63.1
i-units			2,850.4				2,807.5
General partner			247.6				244.3
Accumulated other comprehensive loss			(356.6	)			(186.4	)
Total Kinder Morgan Energy Partners, L.P. partners’ capital			7,018.4				7,210.7
Noncontrolling interests			79.2				81.8
Total Partners’ Capital			7,097.6				7,292.5
Total Liabilities and Partners’ Capital		$	21,793.3			$	21,861.1

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

 

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

(Unaudited)

		Three Months Ended March 31,
		2011				2010
Cash Flows From Operating Activities
Net Income		$	340.9			$	227.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			221.8				227.3
Amortization of excess cost of equity investments			1.5				1.4
Noncash compensation expense allocated from parent (Note 9)			89.9				1.4
Earnings from equity investments			(64.9	)			(46.7	)
Distributions from equity investments			64.8				49.8
Changes in components of working capital:
Accounts receivable			99.7				49.0
Inventories			-				(7.5	)
Other current assets			20.0				23.8
Accounts payable			(39.1	)			(9.1	)
Accrued interest			(148.0	)			(127.8	)
Accrued taxes			33.5				6.1
Accrued liabilities			(20.9	)			(12.4	)
Rate reparations, refunds and other litigation reserve adjustments			(63.0	)			158.0
Other, net			(18.7	)			(25.9	)
Net Cash Provided by Operating Activities			517.5				514.8
Cash Flows From Investing Activities
Acquisitions of assets and investments			(65.9	)			(226.3	)
Capital expenditures			(265.0	)			(218.8	)
Sale or casualty of property, plant and equipment, and other net assets net of removal costs			0.9				13.4
Net proceeds from margin and restricted deposits			43.2				15.9
Contributions to equity investments			(22.2	)			(135.6	)
Distributions from equity investments in excess of cumulative earnings			79.1				57.3
Net Cash Used in Investing Activities			(229.9	)			(494.1	)
Cash Flows From Financing Activities
Issuance of debt			2,522.7				957.0
Payment of debt			(2,304.6	)			(524.0	)
Debt issue costs			(7.1	)			(0.2	)
Increase in cash book overdrafts			3.4				10.8
Proceeds from issuance of common units			81.2				-
Contributions from noncontrolling interests			1.8				1.7
Distributions to partners and noncontrolling interests:
Common units			(247.4	)			(217.7	)
Class B units			(6.0	)			(5.6	)
General Partner			(278.2	)			(245.5	)
Noncontrolling interests			(6.6	)			(6.0	)
Net Cash Used in Financing Activities			(240.8	)			(29.5	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			2.5				(3.4	)
Net increase (decrease) in Cash and Cash Equivalents			49.3				(12.2	)
Cash and Cash Equivalents, beginning of period			129.1				146.6
Cash and Cash Equivalents, end of period		$	178.4			$	134.4
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities		$	-			$	10.5
Assets acquired by the issuance of common units		$	-			$	81.7
Contribution of net assets to investments		$	7.9			$	-
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)		$	251.1			$	213.5
Cash paid during the period for income taxes		$	1.3			$	2.7

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

 

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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

1.  General

 

Organization

 

Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.  We own an interest in or operate approximately 28,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described further in Note 8).  Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals and handle bulk materials like coal and petroleum coke.  We are also the leading provider of carbon dioxide for enhanced oil recovery projects in North America.  Our general partner is owned by Kinder Morgan, Inc., as discussed following.

 

Kinder Morgan, Inc., Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc.

 

Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of Kinder Morgan Kansas, Inc.  Kinder Morgan Kansas, Inc. is a Kansas corporation and indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation.  In July 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057.  The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.  As of March 31, 2011, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate 12.8% interest in us.

 

KMI was formed August 23, 2006 as a Delaware limited liability company principally for the purpose of acquiring (through a wholly-owned subsidiary) all of the common stock of Kinder Morgan Kansas, Inc.  The merger, referred to in this report as the going-private transaction, closed on May 30, 2007 with Kinder Morgan Kansas, Inc. continuing as the surviving legal entity.

 

On February 10, 2011, KMI converted from a Delaware limited liability company named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc., and its outstanding units were converted into classes of capital stock.  On February 16, 2011, KMI completed the initial public offering of its common stock.  All of the common stock that was sold in the offering was sold by existing investors, consisting of funds advised by or affiliated with Goldman, Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC.  No members of management sold shares in the offering and KMI did not receive any proceeds from the offering.  KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.”

 

Kinder Morgan Management, LLC

 

Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company.  Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner.  KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.”

 

More information about the entities referred to above and the delegation of control agreement is contained in our Annual Report on Form 10-K for the year ended December 31, 2010.  In this report, we refer to our Annual Report on Form 10-K for the year ended December 31, 2010 as our 2010 Form 10-K, and we refer to our Amended Annual Report on Form 10-K for the year ended December 31, 2010, as our 2010 Form 10-K/A.  The sole purpose of our amended filing was to correct the signature line of the Report of Independent Registered Public Accounting Firm included in our original filing’s Item 8 “Financial Statements and Supplementary Data.”

 

 

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Basis of Presentation

 

We have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission.  These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America and referred to in this report as the Codification. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with the Codification.  We believe, however, that our disclosures are adequate to make the information presented not misleading.

 

In addition, our consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair statement of our financial results for the interim periods, and certain amounts from prior periods have been reclassified to conform to the current presentation.  Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2010 Form 10-K/A.

 

Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise.  Canadian dollars are designated as C$.  Our consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.

 

In addition, our financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 9 “Related Party Transactions—Asset Acquisitions,” KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa.  Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability.  Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.

 

Limited Partners’ Net Income per Unit

 

We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period.  The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit  are made in accordance with the “Earnings per Share” Topic of the Codification.

 

 

2.  Acquisitions, Joint Ventures, and Divestitures

 

Acquisitions

 

Watco Companies, LLC

 

On January 3, 2011, we purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50.0 million in cash in a private transaction.  In connection with our purchase of these preferred shares, the most senior equity security of Watco, we entered into a limited liability company agreement with Watco that provides us certain priority and participating cash distribution and liquidation rights.  Pursuant to the agreement, we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we participate partially in additional profit distributions at a rate equal to 0.5%.  The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers.  As of December 31, 2010, we placed our $50.0 million investment in a cash escrow account and we included this amount within “Restricted Deposits” on our accompanying balance sheet.  As of March 31, 2011, our $50.0 million investment is included within “Investments”  on our accompanying balance sheet.  The acquired investment complemented our existing rail transload operations.  We account for this investment under the equity method of accounting, and we include it in our Terminals business segment.

 

 

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Watco Companies, LLC is a privately owned, Pittsburg, Kansas based transportation company that was formed in 1983.  It is the largest privately held short line railroad company in the United States, operating 22 short line railroads on approximately 3,500 miles of leased and owned track.  It also operates transload/intermodal and mechanical services divisions.  Our investment provides capital to Watco for further expansion of specific projects, complements our existing terminal network, provides our customers more transportation services for many of the commodities that we currently handle, and offers us the opportunity to share in additional growth opportunities through new projects.

 

Pro Forma Information                                                  

 

Pro forma consolidated income statement information that gives effect to all of the acquisitions we have made and all of the joint ventures we have entered into since January 1, 2010 as if they had occurred as of January 1, 2010 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

 

Joint Ventures

 

Deeprock North, LLC

 

On February 17, 2011, our subsidiary Kinder Morgan Cushing LLC and Mecuria Energy Trading, Inc. entered into formal agreements for a crude oil storage joint venture located in Cushing, Oklahoma. On this date, we contributed $15.9 million for a 50% ownership interest in an existing crude oil tank farm that has storage capacity of one million barrels, and we expect to invest an additional $8.8 million for the construction of three new storage tanks that will provide incremental storage capacity of 750,000 barrels.  The new tanks are expected to be in service by the end of the third quarter of 2011.  The joint venture is named Deeprock North, LLC.  Deeprock Energy owns a 12.02% member interest in Deeprock North, LLC and will remain construction manager and operator of the joint venture.  Mecuria owns the remaining 37.98% member interest and will remain the anchor tenant for the joint venture’s crude oil capacity for the next five years with an option to extend.  In addition, we entered into a development agreement with Deeprock Energy that gives us an option to participate in future expansions on Deeprock’s remaining 254 acres of undeveloped land.

 

We account for our investment under the equity method of accounting, and our investment and our pro rata share of Deeprock North LLC’s operating results are included as part of our Terminals business segment.  As of March 31, 2011, our net equity investment in Deeprock North, LLC totaled $16.0 million and is included within “Investments” on our accompanying consolidated balance sheet.  In April 2011, we contributed an additional $2.1 million to Deeprock North as partial funding for its ongoing tankage and truck rack expansion projects.

 

Megafleet Towing Co., Inc. Assets

 

On February 9, 2011, we sold a marine vessel to Kirby Inland Marine, L.P., and additionally, we and Kirby formed a joint venture named Greens Bayou Fleeting, LLC.  Pursuant to the joint venture agreement, we sold our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 to the joint venture for $4.1 million in cash and a 49% ownership interest in the joint venture.  Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest.  Related to the above transactions, we recorded a loss of $5.5 million ($4.1 million after tax) in the fourth quarter of 2010 to write down the carrying value of the net assets to be sold to their estimated fair values as of December 31, 2010.  In the first quarter of 2011, after final reconciliation and measurement of all of the net assets sold, we recognized a combined $2.2 million increase in income from the sale of these net assets, primarily consisting of a $1.9 million reduction in income tax expense, which is included within the caption “Income Taxes” in our accompanying consolidated statement of income for the three months ended March 31, 2011.  Additionally, the sale of our ownership interest resulted in a $10.6 million non-cash reduction in our goodwill (see Note 3), and was a transaction with a related party (see Note 9).  Information about our acquisition of assets from Megafleet Towing Co., Inc. is described more fully in Note 3 to our consolidated financial statements included in our 2010 Form 10-K/A.

 

Divestitures Subsequent to March 31, 2011                                                                       

 

River Consulting, LLC and Devco USA L.L.C.

 

Effective April 1, 2011, we sold 51% ownership interests in two separate wholly-owned subsidiaries to two separate buyers, both Oklahoma limited liability companies, for an aggregate consideration of $5.1 million, consisting of a $4.1 million note receivable and $1.0 million in cash.  Following the sale, we continue to own 49% membership interests in both River Consulting LLC, a Louisiana limited liability company engaged in the business of providing engineering, consulting and management services, and Devco USA L.L.C., an Oklahoma limited liability company engaged in the business of processing, handling and marketing sulfur, and selling related pouring equipment.  We now account for our retained investments under the equity method of accounting.  At the time of the sale, the combined carrying value of the net assets (and members’ capital on a 100% basis) of both entities totaled approximately $7.5 million and consisted mostly of trade receivables and technology-based assets.  The sale of 51% of each of these two subsidiaries will not have a material impact on our results of operations or our cash flows.

 

 

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3.   Intangibles

 

Goodwill

 

We evaluate goodwill for impairment on May 31 of each year.  For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines; (iv) CO 2 ; (v) Terminals; and (vi) Kinder Morgan Canada.  There were no impairment charges resulting from our May 31, 2010 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

 

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 ten times cash flows) discounted at a rate of 9.0%.  The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.

 

Changes in the gross amounts of our goodwill and accumulated impairment losses for the three months ended March 31, 2011 are summarized as follows (in millions):

 

		Products Pipelines				Natural Gas Pipelines				CO 2				Terminals				Kinder Morgan Canada				Total
Historical Goodwill.		$	263.2			$	337.0			$	46.1			$	337.9			$	626.5			$	1,610.7
Accumulated impairment losses(a).			-				-				-				-				(377.1	)			(377.1	)
Balance as of December 31, 2010			263.2				337.0				46.1				337.9				249.4				1,233.6
Acquisitions.			-				-				-				-				-				-
Disposals(b).			-				-				-				(10.6	)			-				(10.6	)
Impairments			-				-				-				-				-				-
Currency translation adjustments			-				-				-				-				6.4				6.4
Balance as of March 31, 2011		$	263.2			$	337.0			$	46.1			$	327.3			$	255.8			$	1,229.4

__________

(a)

On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007.  Following the provisions of generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired.  Based on this determination, KMI recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment is now included in our accumulated impairment losses. We have no other goodwill impairment losses.

(b)

First quarter 2011 disposal related to the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 (discussed further in Note 2.)

 

In addition, we identify any premium or excess cost we pay over our proportionate share of the underlying fair value of net assets acquired and accounted for as investments under the equity method of accounting.  This premium or excess cost is referred to as equity method goodwill and is also not subject to amortization but rather to impairment testing.  For all investments we own containing equity method goodwill, no event or change in circumstances that may have a significant adverse effect on the fair value of our equity investments has occurred during the first three months of 2011.  As of March 31, 2011 and December 31, 2010, we reported $286.9 million and $283.0 million, respectively, in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.  The increase in our equity method goodwill since December 31, 2010 was due to measurement period adjustments related to our acquisition of a 50% ownership interest in KinderHawk Field Services LLC in May 2010.

 

 

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Other Intangibles

 

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value.  These intangible assets have definite lives and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.  Following is information related to our intangible assets subject to amortization (in millions):

 

		March 31, 2011				December 31, 2010
Customer relationships, contracts and agreements
Gross carrying amount		$	398.8			$	399.8
Accumulated amortization			(121.6	)			(112.0	)
Net carrying amount			277.2				287.8
Technology-based assets, lease value and other
Gross carrying amount			15.7				17.9
Accumulated amortization			(3.6	)			(3.5	)
Net carrying amount			12.1				14.4
Total Other intangibles, net		$	289.3			$	302.2

 

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives.  Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.  For the three months ended March 31, 2011 and 2010, the amortization expense on our intangibles totaled $9.7 million and $11.3 million, respectively.  As of March 31, 2011, the weighted average amortization period for our intangible assets was approximately 13.6 years, and our estimated amortization expense for these assets for each of the next five fiscal years (2012 – 2016) is approximately $33.4 million, $29.5 million, $26.4 million, $23.6 million and $19.9 million, respectively.

 

 

4.  Debt

 

We classify our debt based on the contractual maturity dates of the underlying debt instruments.  We defer costs associated with debt issuance over the applicable term.  These costs are then amortized as interest expense in our consolidated statements of income.

 

The net carrying amount of our debt (including both short-term and long-term amounts and excluding the value of interest rate swap agreements) as of March 31, 2011 and December 31, 2010 was $11,748.8 million and $11,539.8 million, respectively.  The weighted average interest rate on all of our borrowings was approximately 4.44% during the first quarter of 2011, and approximately 4.32% during the first quarter of 2010.

Our outstanding short-term debt as of March 31, 2011 was $1,333.2 million.  The balance consisted of (i) $500.0 million in principal amount of 9.00% senior notes due February 1, 2019, that may be repurchased by us at the option of the holder on February 1, 2012 pursuant to certain repurchase provisions contained in the bond indenture; (ii) $450.0 million in principal amount of 7.125% senior notes due March 15, 2012 (including discount, the notes had a carrying amount of $449.8 million as of March 31, 2011); (iii) $343.0 million of commercial paper borrowings; (iv) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, that are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (v) a $9.4 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); and (vi) a $7.3 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes).

 

 

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Credit Facility

 

Our $2.0 billion three-year, senior unsecured revolving credit facility expires June 23, 2013 and can be amended to allow for borrowings of up to $2.3 billion.  The credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate.  Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our $2.0 billion commercial paper program.  There were no borrowings under the credit facility as of March 31, 2011 or as of December 31, 2010.

 

As of March 31, 2011, the amount available for borrowing under our credit facility was reduced by   a combined amount of $579.8 million, consisting of $343.0 million of commercial paper borrowings and $236.8 million of letters of credit, consisting of: (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 our Pacific operations’ pipelines in the state of California; (ii) a combined $87.9 million in three letters of credit that support tax-exempt bonds; (iii) a $16.2 million letter of credit that supports debt securities issued by the Express pipeline system; (iv) a $16.1 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $16.6 million in other letters of credit supporting other obligations of us and our subsidiaries.

 

Commercial Paper Program

 

Our commercial paper program provides for the issuance of $2.0 billion of commercial paper.  Our $2.0 billion unsecured three-year bank credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.  As of March 31, 2011, we had $343.0 million of commercial paper outstanding with an average interest rate of approximately 0.35%.  As of December 31, 2010, we had $522.1 million of commercial paper outstanding with an average interest rate of 0.67%.  The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2011 and 2010.  In the near term, we expect that our short-term liquidity and financing needs will be met primarily through borrowings made under our commercial paper program.

 

Kinder Morgan Energy Partners, L.P. Senior Notes

 

On March 4, 2011, we completed a public offering of $1.1 billion in principal amount of senior notes in two separate series, consisting of $500 million of 3.500% notes due March 1, 2016, and $600 million of 6.375% notes due March 1, 2041.  We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $1,092.7 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

In addition, on March 15, 2011, we paid $700 million to retire the principal amount of our 6.75% senior notes that matured on that date.  We used both cash on hand and borrowings under our commercial paper program to repay the maturing senior notes.

 

Subsidiary Debt

 

Kinder Morgan Operating L.P. “A” Debt

 

Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own.  As part of our purchase price consideration, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million.  We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%.  Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and the principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008.  We paid the fourth installment on March 31, 2011, and as of this date, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $9.4 million.  As of December 31, 2010, the net present value of the note was $19.2 million.

 

 

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Kinder Morgan Texas Pipeline, L.P. Debt

 

Our subsidiary, Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes, which were assumed on August 1, 2005 when we acquired a natural gas storage facility located in Liberty County, Texas from a third party.  The notes have a fixed annual stated interest rate of 8.85%; however, we valued the debt equal to the present value of amounts to be paid determined using an approximate interest rate of 5.23%.  The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million, and the final payment is due January 2, 2014.  During the first quarter of 2011, we paid a combined principal amount of $1.8 million, and as of March 31, 2011, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $21.8 million.  Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and 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.  As of December 31, 2010, the outstanding balance under the notes was $23.6 million.

 

Interest Rate Swaps

 

Information on our interest rate swaps is contained in Note 6 “Risk Management—Interest Rate Risk Management.”

 

Contingent Debt

 

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.  Most of these agreements are with entities that are not consolidated in our financial statements; however, we have invested in and hold equity ownership interests in these entities.

 

As of March 31, 2011, our contingent debt obligations with respect to these investments, as well as our obligations with respect to related letters of credit, are summarized below (dollars in millions):

 

Entity		Our Ownership Interest			Investment Type		Total Entity Debt					Our Contingent Share of Entity Debt			(a)
Fayetteville Express Pipeline LLC(b)			50	%	Limited Liability		$	962.5		(c)		$	481.3
Cortez Pipeline Company(d)			50	%	General Partner		$	140.1		(e)		$	86.2		(f)
Nassau County, Florida Ocean Highway and Port Authority(g)			N/A		N/A			N/A				$	18.3		(h)

_________

(a)	Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy its obligations.
(b)	Fayetteville Express Pipeline LLC is a limited liability company and the owner of the Fayetteville Express natural gas pipeline system.  The remaining limited liability company member interest in Fayetteville Express Pipeline LLC is owned by Energy Transfer Partners, L.P.
(c)	Amount represents borrowings under a $1.1 billion, unsecured revolving bank credit facility that is due May 11, 2012.
(d)	Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system. 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.
(e)	Amount consists of (i) $32.1 million aggregate principal amount of Series D notes due May 15, 2013 (interest on the Series D notes is paid annually and based on a fixed interest rate of 7.14% per annum); (ii) $100.0 million of variable rate Series E notes due December 11, 2012 (interest on the Series E notes is paid quarterly and based on an interest rate of three-month LIBOR plus a spread); and (iii) $8.0 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.
(f)	We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt ($70.1 million).  In addition, as of March 31, 2011, Shell Oil Company shares our several guaranty obligations jointly and severally for $32.1 million of Cortez’s debt balance related to the Series D notes; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of March 31, 2011, we have a letter of credit in the amount of $16.1 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $32.1 million related to the Series D notes.   Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency.  The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation.  The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.
(g)	Arose from our Vopak terminal acquisition in July 2001.  Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida.
(h)	We have 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.  Our 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.  As of March 31, 2011, this letter of credit had a face amount of $18.3 million.

 

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On February 25, 2011, Midcontinent Express Pipeline LLC entered into a three-year $75.0 million unsecured revolving bank credit facility that is due February 25, 2014.  This credit facility replaced Midcontinent Express’ previous $175.4 million credit facility that was terminated on February 28, 2011, and on this same date, each of its two member owners, including us, were released from their respective debt obligations under the previous guaranty agreements.  Accordingly, we no longer have a contingent debt obligation with respect to Midcontinent Express Pipeline LLC.  For additional information regarding our debt facilities and our contingent debt agreements, see Note 8 “Debt” and Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements included in our 2010 Form 10-K/A.

 

 

5.  Partners’ Capital

 

Limited Partner Units

 

As of March 31, 2011 and December 31, 2010, our partners’ capital included the following limited partner units:

 

		March 31,				December 31,
		2011				2010
Common units			220,012,759				218,880,103
Class B units			5,313,400				5,313,400
i-units			93,506,543				91,907,987
Total limited partner units			318,832,702				316,101,490

 

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

 

As of March 31, 2011, our total common units consisted of 203,642,331 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.  As of December 31, 2010, our total common units consisted of 202,509,675 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.

 

As of both March 31, 2011 and December 31, 2010, all of our 5,313,400 Class B units were held by a wholly-owned subsidiary of KMI.  The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange.

 

 

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As of both March 31, 2011 and December 31, 2010, all of our i-units were held by KMR.  Our i-units are a separate class of limited partner interests in us and are not publicly traded.  The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units.  When cash is paid to the holders of our common units, we issue additional i-units to KMR.  The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.

 

Changes in Partners’ Capital

 

For each of the three month periods ended March 31, 2011 and 2010, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income (loss) are summarized as follows (in millions):

 

		Three Months Ended March 31,
		2011												2010
		KMP				Noncontrolling Interests				Total				KMP				Noncontrolling interests				Total
Beginning Balance		$	7,210.7			$	81.8			$	7,292.5			$	6,644.5			$	79.6			$	6,724.1
Units issued as consideration pursuant to common unit compensation plan for non-employee directors			0.2				-				0.2				0.2				-				0.2
Units issued as consideration in the acquisition of assets			-				-				-				81.7				-				81.7
Units issued for cash			81.2				-				81.2				-				-				-
Distributions paid in cash			(531.6	)			(6.6	)			(538.2	)			(468.8	)			(6.0	)			(474.8	)
Noncash compensation expense allocated from KMI(a)			89.0				0.9				89.9				1.4				-				1.4
Cash contributions			-				1.8				1.8				-				1.7				1.7
Other adjustments			1.3				-				1.3				-				-				-
Comprehensive income:
Net Income			337.8				3.1				340.9				225.3				2.1				227.4
Other comprehensive income:
Change in fair value of derivatives utilized for hedging purposes			(259.8	)			(2.6	)			(262.4	)			24.4				0.2				24.6
Reclassification of change in fair value of derivatives to  net income			52.5				0.5				53.0				47.0				0.5				47.5
Foreign currency translation adjustments			50.1				0.5				50.6				59.2				0.6				59.8
Adjustments to pension and other postretirement benefit plan liabilities			(13.0	)			(0.2	)			(13.2	)			(2.3	)			-				(2.3	)
Total other comprehensive income(loss)			(170.2	)			(1.8	)			(172.0	)			128.3				1.3				129.6
Comprehensive income			167.6				1.3				168.9				353.6				3.4				357.0
Ending Balance		$	7,018.4			$	79.2			$	7,097.6			$	6,612.6			$	78.7			$	6,691.3

____________

 

(a)	For further information about this expense, see Note 9.  We do not have any obligation, nor do we expect to pay any amounts related to this expense.

 

During the first three months of both 2011 and 2010, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.

 

Equity Issuances

 

On February 25, 2011, we entered into a second amended and restated equity distribution agreement with UBS Securities LLC to provide for the offer and sale of common units having an aggregate offering price of up to $1.2 billion (up from an aggregate offering price of up to $600 million under our first amended and restated agreement) from time to time through UBS, as our sales agent.  During the three months ended March 31, 2011, we issued 1,130,206 of our common units pursuant to this equity distribution agreement, and after commissions of $0.6 million, we received net proceeds of $81.2 million from the issuance of these common units.  We used the proceeds to reduce the borrowings under our commercial paper program.  For additional information regarding our equity distribution agreement, see Note 10 to our consolidated financial statements included in our 2010 Form 10-K/A.

 

 

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Income Allocation and Declared Distributions

 

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

 

On February 14, 2011, we paid a cash distribution of $1.13 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended December 31, 2010.  KMR, our sole i-unitholder, received a distribution of 1,598,556 i-units from us on February 14, 2011, based on the $1.13 per unit distributed to our common unitholders on that date.  The distributions were declared on January 19, 2011, payable to unitholders of record as of January 31, 2011.

 

Our February 14, 2011 incentive distribution payment to our general partner for the quarterly period ended December 31, 2010 totaled $274.6 million; however, this incentive distribution was affected by a waived incentive distribution equal to $7.0 million related to common units issued to finance a portion of our May 2010 acquisition of a 50% interest in KinderHawk Field Services LLC joint venture (our general partner has agreed not to take incentive distributions related to this acquisition through year-end 2011).  Our distribution of $1.05 per unit paid on February 12, 2010 for the fourth quarter of 2009 required an incentive distribution to our general partner of $242.3 million.  The increased incentive distribution to our general partner paid for the fourth quarter of 2010 over the incentive distribution paid for the fourth quarter of 2009 reflects the increase in the amount distributed per unit as well as the issuance of additional units.

 

Subsequent Events

 

In the first week of April 2011, we issued 114,690 of our common units for the settlement of sales made on or before March 31, 2011 pursuant to our equity distribution agreement.  After commissions of $0.1 million, we received net proceeds of $8.4 million for the issuance of these 114,690 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

On April 20, 2011, we declared a cash distribution of $1.14 per unit for the quarterly period ended March 31, 2011.  The distribution will be paid on May 13, 2011, to unitholders of record as of April 29, 2011.  Our common unitholders and our Class B unitholder will receive cash.  KMR will receive a distribution of 1,599,149 additional i-units based on the $1.14 distribution per common unit.  For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017102) will be issued.  This fraction was determined by dividing:

 

▪ $1.14, the cash amount distributed per common unit

 

by

 

▪ $66.659, the average of KMR’s shares’ closing market prices from April 12-26, 2011, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.

 

Our declared distribution for the first quarter of 2011 of $1.14 per unit will result in an incentive distribution to our general partner of $280.0 million (including the effect of a waived incentive distribution amount of $7.1 million related to our KinderHawk acquisition, as discussed above).  Comparatively, our distribution of $1.07 per unit paid on May 14, 2010 for the first quarter of 2010 resulted in an incentive distribution payment to our general partner in the amount of $249.4 million.

 

 

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6.  Risk Management

 

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil.  We also have exposure to interest rate risk as a result of the issuance of our debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.

 

Energy Commodity Price 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 the forecasted purchase or sale of these products.  Specifically, these risks are primarily associated with price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage.  Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations.

 

Our principal use of energy commodity derivative contracts is to mitigate the risk associated with unfavorable market movements in the price of energy commodities.  Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.

 

For derivative contracts that are designated and qualify as cash flow hedges pursuant to generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective (as defined by generally accepted accounting principles) in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are commodity sales).  The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion as defined by generally accepted accounting principles), is recognized in earnings during the current period.  The effectiveness of hedges using an option contract may be assessed based on changes in the option’s intrinsic value with the change in the time value of the contract being excluded from the assessment of hedge effectiveness.  Changes in the excluded component of the change in an option’s time value are included currently in earnings.  During the first quarter of 2011, we recognized a net gain of $3.7 million related to crude oil hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.  During the first quarter of 2010, we recognized a net gain of $6.3 million related to crude oil and natural gas hedges that resulted from hedge ineffectiveness and amounts excluded from effectiveness testing.

 

Additionally, during the three months ended March 31, 2011 and 2010, we reclassified losses of $53.0 million and $47.5 million, respectively, from “Accumulated other comprehensive loss” into earnings.  No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, the amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred).  The proceeds or payments resulting from the settlement of our cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.

 

The “Accumulated other comprehensive loss” balance included in our Partners’ Capital was $356.6 million as of March 31, 2011, and $186.4 million as of December 31, 2010.  These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $514.4 million as of March 31, 2011 and $307.1 million as of December 31, 2010.  Approximately $347.4 million of the total loss amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of March 31, 2011 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts could vary materially as a result of changes in market prices.  As of March 31, 2011, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2015.

 

 

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As of March 31, 2011, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

 

	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil	(24.9) million barrels
Natural gas fixed price	(28.8) billion cubic feet
Natural gas basis	(28.8) billion cubic feet
Derivatives not designated as hedging contracts
Natural gas basis	1.7 billion cubic feet

For derivative contracts that are not designated as a hedge for accounting purposes, all realized and unrealized gains and losses are recognized in the statement of income during the current period.  These types of transactions include basis spreads, basis-only positions and gas daily swap positions.  We primarily enter into these positions to economically hedge an exposure through a relationship that does not qualify for hedge accounting.  Until settlement occurs, this will result in non-cash gains or losses being reported in our operating results.

 

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.

 

Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to variable rates, resulting in future cash flows that vary with the market rate of interest.  These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes.  For derivative contracts that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.

 

As of March 31, 2011, we had a combined notional principal amount of $5,275 million of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.  All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of March 31, 2011, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through January 15, 2038.

 

As of December 31, 2010, we had a combined notional principal amount of   $4,775 million of fixed-to-variable interest rate swap agreements.  In the first quarter of 2011, we entered into four additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. Each agreement effectively converts a portion of the interest expense associated with our 3.50% senior notes due March 1, 2016 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.

 

Fair Value of Derivative Contracts

 

The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” on our accompanying consolidated balance sheets.  The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of March 31, 2011 and December 31, 2010 (in millions):

 

 

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Fair Value of Derivative Contracts
			Asset derivatives								Liability derivatives
			March 31,				December 31,				March 31,				December 31,
			2011				2010				2011				2010
	Balance sheet location		Fair value				Fair value				Fair value				Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Current		$	19.9			$	20.1			$	(372.4	)		$	(275.9	)
	Non-current			24.6				43.1				(189.9	)			(103.0	)
Subtotal				44.5				63.2				(562.3	)			(378.9	)
Interest rate swap agreements	Current			10.6				-				-				-
	Non-current			166.3				217.6				(92.4	)			(69.2	)
Subtotal				176.9				217.6				(92.4	)			(69.2	)
Total				221.4				280.8				(654.7	)			(448.1	)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current			4.7				3.9				(8.1	)			(5.6	)
Total				4.7				3.9				(8.1	)			(5.6	)
Total derivatives			$	226.1			$	284.7			$	(662.8	)		$	(453.7	)

____________

 

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements.  As of March 31, 2011 and December 31, 2010, this unamortized premium totaled $445.9 million and $456.5 million, respectively, and as of March 31, 2011, the weighted average amortization period for this premium was approximately 17.0 years.

 

Effect of Derivative Contracts on the Income Statement

 

The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three months ended March 31, 2011 and 2010 (in millions):

 

Derivatives in fair value hedging relationships	Location of gain/(loss) recognized in income on derivative		Amount of gain/(loss) recognized in income on derivative(a)							Hedged items in fair value hedging relationships	Location of gain/(loss) recognized in income on related hedged item		Amount of gain/(loss) recognized in income on related hedged items(a)
			Three Months Ended										Three Months Ended
			March 31,										March 31,
			2011				2010						2011				2010
Interest rate swap agreements	Interest, net – income/(expense)		$	(63.9	)		$	65.6		Fixed rate debt	Interest, net – income/(expense)		$	63.9			$	(65.6	)
Total			$	(63.9	)		$	65.6		Total			$	63.9			$	(65.6	)

____________

 

(a)

Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt which exactly offset each other as a result of no hedge ineffectiveness.  Amounts do not reflect the impact on interest expense from the interest rate swap agreements under which we pay variable rate interest and receive fixed rate interest.

 

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Derivatives in cash flow hedging relationships	Amount of gain/(loss) recognized in OCI on derivative (effective portion)								Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)	Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)								Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Three Months									Three Months									Three Months
	Ended March 31,									Ended March 31,									Ended March 31,
	2011				2010					2011				2010					2011				2010
Energy commodity derivative contracts		$	(262.4	)		$	24.6		Revenues-natural gas sales		$	0.9			$	-		Revenues-product sales and other		$	3.7			$	5.4
									Revenues-product sales and other			(65.2	)			(50.0	)
									Gas purchases and other costs of sales			11.3				2.5		Gas purchases and other costs of sales			-				0.9
Total		$	(262.4	)		$	24.6		Total		$	(53.0	)		$	(47.5	)	Total		$	3.7			$	6.3

____________

 

Derivatives not designated as  hedging contracts	Location of gain/(loss) recognized In income on derivative		Amount of gain/(loss) recognized in income on derivative
			Three Months Ended March 31,
			2011				2010
Energy commodity derivative contracts	Gas purchases and other costs of sales		$	0.1			$	0.7
Total			$	0.1			$	0.7

____________

Credit Risks

 

We have counterparty credit risk as a result of our use of financial 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 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 futures, options or stock exchanges.  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.

 

The maximum potential exposure to credit losses on our derivative contracts as of March 31, 2011 was (in millions):

 

		Asset position
Interest rate swap agreements		$	176.9
Energy commodity derivative contracts			49.2
Gross exposure			226.1
Netting agreement impact			(49.4	)
Net exposure		$	176.7

 

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In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts.  As of   both March 31, 2011 and December 31, 2010, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.

 

As of March 31, 2011, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $4.4 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet.  As of December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the–counter swap agreements had margin deposits with us totaling $2.4 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet.

 

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating.  Based on contractual provisions as of March 31, 2011, we estimate that if our credit rating was downgraded, we would have the following additional collateral obligations (in millions):

 

Credit ratings downgraded (a)		Incremental obligations				Cumulative obligations(b)
One notch to BBB-/Baa3		$	-			$	4.4
Two notches to below BBB-/Baa3 (below investment grade)		$	87.0			$	91.4

_________

(a)	If there are split ratings among the independent credit rating agencies, most counterparties use the higher credit rating to determine our incremental collateral obligations, while the remaining use the lower credit rating.  Therefore, a two notch downgrade to below BBB-/Baa3 by one agency would not trigger the entire $87.0 million incremental obligation.
(b)	Includes current posting at current rating.

 

7.  Fair Value

 

The Codification emphasizes that fair value is a market-based measurement that should be determined based on assumptions (inputs) that market participants would use in pricing an asset or liability.  Inputs may be observable or unobservable, and valuation techniques used to measure fair value should maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Accordingly, the Codification establishes a hierarchal disclosure framework that ranks the quality and reliability of information used to determine fair values.  The hierarchy is associated with the level of pricing observability utilized in measuring fair value and defines three levels of inputs to the fair value measurement process—quoted prices are the most reliable valuation inputs, whereas model values that include inputs based on unobservable data are the least reliable.  Each fair value measurement must 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 fair value 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).

 

 

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Fair Value of Derivative Contracts

 

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of March 31, 2011 and December 31, 2010, based on the three levels established by the Codification (in millions).  The fair value measurements in the tables below do not include cash margin deposits made by us or our counterparties, which would be reported within “Restricted deposits” and “Accrued other liabilities,” respectively, in our accompanying consolidated balance sheets.

 

		Asset fair value measurements using
		Total				Quoted prices in active markets for identical assets (Level 1)				Significant other observable inputs (Level 2)				Significant unobservable inputs (Level 3)
As of March 31, 2011
Energy commodity derivative contracts(a)		$	49.2			$	12.8			$	6.9			$	29.5
Interest rate swap agreements		$	176.9			$	-			$	176.9			$	-
As of December 31, 2010
Energy commodity derivative contracts(a)		$	67.1			$	-			$	23.5			$	43.6
Interest rate swap agreements		$	217.6			$	-			$	217.6			$	-

____________

 

		Liability fair value measurements using
		Total				Quoted prices in active markets for identical liabilities (Level 1)				Significant other observable inputs (Level 2)				Significant unobservable inputs (Level 3)
As of March 31, 2011
Energy commodity derivative contracts(a)		$	(570.4	)		$	(8.7	)		$	(529.0	)		$	(32.7	)
Interest rate swap agreements		$	(92.4	)		$	-			$	(92.4	)		$	-
As of December 31, 2010
Energy commodity derivative contracts(a)		$	(384.5	)		$	-			$	(359.7	)		$	(24.8	)
Interest rate swap agreements		$	(69.2	)		$	-			$	(69.2	)		$	-

____________

 

(a)	Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC West Texas Intermediate swaps and OTC natural gas swaps that are settled on NYMEX.  Level 3 consists primarily of natural gas basis swaps and West Texas Intermediate options.

 

 

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The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three months ended March 31, 2011 and 2010 (in millions):

 

Significant unobservable inputs (Level 3)

 

		Three Months Ended
		March 31,
		2011				2010
Derivatives-net asset (liability)
Beginning of period		$	18.8			$	13.0
Transfers into Level 3			-				-
Transfers out of Level 3			-				-
Total gains or (losses)			-				-
Included in earnings			0.1				-
Included in other comprehensive income			(22.8	)			8.6
Purchases			4.6				-
Issuances			-				-
Sales			-				-
Settlements			(3.9	)			1.0
End of period		$	(3.2	)		$	22.6
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date		$	-			$	(0.1	)

Fair Value of Financial Instruments

 

Fair value as used in the disclosure of financial instruments represents the amount at which an instrument could be exchanged in a current transaction between willing parties.  As of each reporting date, the estimated fair value of our outstanding publicly-traded debt is based upon quoted market prices, if available, and for all other debt, fair value is based upon prevailing interest rates currently available to us.  In addition, we adjust (discount) the fair value measurement of our long-term debt for the effect of credit risk.

 

The estimated fair value of our outstanding debt balance as of March 31, 2011 and December 31, 2010 (both short-term and long-term, but excluding the value of interest rate swaps) is disclosed below (in millions):

 

		March 31, 2011								December 31, 2010
		Carrying Value				Estimated fair value				Carrying Value				Estimated fair value
Total debt		$	11,748.8			$	12,589.1			$	11,539.8			$	12,443.4

 

8.  Reportable Segments

 

We divide our operations into five reportable business segments.  These segments and their principal source of revenues are as follows:

 

▪

Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;

 

▪

Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;

 

▪

CO 2 —the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;

 

▪

Terminals—the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and

 

 

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▪

Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.

 

We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense.  Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision maker organizes their operations for optimal performance and resource allocation.  Each segment is managed separately because each segment involves different products and marketing strategies.

 

Financial information by segment follows (in millions):

 

		Three Months Ended March 31,
		2011				2010
Revenues
Products Pipelines
Revenues from external customers		$	225.6			$	207.5
Natural Gas Pipelines
Revenues from external customers			1,019.4				1,236.7
CO 2
Revenues from external customers			340.8				321.8
Terminals
Revenues from external customers			331.4				303.8
Intersegment revenues			0.3				0.3
Kinder Morgan Canada
Revenues from external customers			75.6				59.8
Total segment revenues			1,993.1				2,129.9
Less: Total intersegment revenues			(0.3	)			(0.3	)
Total consolidated revenues		$	1,992.8			$	2,129.6

 

		Three Months Ended March 31,
		2011				2010
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(a)
Products Pipelines(b)		$	180.5			$	6.4
Natural Gas Pipelines			222.6				220.6
CO 2			262.0				253.2
Terminals			174.4				150.5
Kinder Morgan Canada			47.9				45.0
Total segment earnings before DD&A			887.4				675.7
Total segment depreciation, depletion and amortization			(221.8	)			(227.3	)
Total segment amortization of excess cost of investments			(1.5	)			(1.4	)
General and administrative expenses(c)			(189.2	)			(101.1	)
Unallocable interest expense, net of interest income			(131.7	)			(116.3	)
Unallocable income tax expense			(2.3	)			(2.2	)
Total consolidated net income		$	340.9			$	227.4

 

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		March 31, 2011				December 31, 2010
Assets
Products Pipelines		$	4,375.1			$	4,369.1
Natural Gas Pipelines			8,681.5				8,809.7
CO 2			2,127.0				2,141.2
Terminals			4,243.6				4,138.6
Kinder Morgan Canada			1,901.4				1,870.0
Total segment assets			21,328.6				21,328.6
Corporate assets(d)			464.7				532.5
Total consolidated assets		$	21,793.3			$	21,861.1

____________

 

(a)	Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
(b)	First quarter 2010 includes a $158.0 million increase in expense associated with rate case liability adjustments.
(c)	First quarter 2011 includes an $87.1 million increase in expense associated with a one-time special cash bonus payment that will be paid to non-senior management employees in May 2011; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense.
(d)	Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to the fair value of interest rate swaps.

 

9.  Related Party Transactions

 

Notes Receivable

 

Plantation Pipe Line Company

 

We have a current note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee.  The note provides for semiannual payments of principal and interest on June 30 and December 31 each year, with a final principal payment due July 20, 2011.  As of both March 31, 2011 and December 31, 2010, the outstanding note receivable balance was $82.1 million, and we included this amount within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheets.

 

Express US Holdings LP

 

In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system from KMI on August 28, 2008, we acquired a long-term investment in a C$113.6 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system.  The debenture is denominated in Canadian dollars, due in full on January 9, 2023, bears interest at the rate of 12.0% per annum, and provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year.  As of March 31, 2011 and December 31, 2010, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $117.2 million and $114.2 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

 

Other Receivables and Payables

 

As of March 31, 2011 and December 31, 2010, our related party receivables (other than notes receivable discussed above in “—Notes Receivable”) totaled $9.9 million and $15.4 million, respectively.  The March 31, 2011 amount included $7.8 million within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet, primarily consisting of amounts due from (i) Plantation Pipe Line Company; (ii) the Express pipeline system; and (iii) Natural Gas Pipeline Company of America LLC, a 20%-owned equity investee of KMI and referred to in this report as NGPL.  The December 31, 2010 receivables amount consisted of (i) $8.2 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $7.2 million of natural gas imbalance receivables included within “Other current assets.”  The $8.2 million amount primarily related to accounts and interest receivables due from (i) the Express pipeline system; (ii) NGPL; and (iii) Plantation Pipe Line Company.  Our related party natural gas imbalance receivables consisted of amounts due from NGPL.

 

 

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As of March 31, 2011 and December 31, 2010, our related party payables totaled $8.4 million and $8.8 million, respectively.  The March 31, 2011 related party payable amount included a $6.7 million payable to KMI included within “Accounts payable” on our accompanying balance sheet.  The December 31, 2010 amount consisted of (i) $5.1 million included within “Accounts payable” and primarily related to amounts due to KMI; and (ii) $3.7 million of natural gas imbalance payables included within “Accrued other current liabilities” and consisting of amounts due to the Rockies Express pipeline system.

 

Asset Acquisitions

 

In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; and (ii) all of the ownership interest in TransColorado Gas Transmission Company LLC from two wholly-owned subsidiaries of KMI on November 1, 2004, KMI agreed to indemnify us and our general partner with respect to approximately $733.5 million of our debt.  KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.

 

Asset Divestitures

 

Mr. C. Berdon Lawrence, a non-management director on the boards of our general partner and KMR, is also Chairman Emeritus of the Board of Kirby Corporation.  On February 9, 2011, we sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, we and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC.  For more information about these transactions, see Note 2.

 

Noncash Compensation Expense

 

In the first quarters of 2011 and 2010, KMI allocated to us certain noncash compensation expenses totaling $89.9 million and $1.4 million, respectively.  The amounts included expenses of $2.8 million and $1.4 million, respectively, associated with KMI’s May 2007 going–private transaction, and for 2011 only, an expense of $87.1 million associated with a one-time special cash bonus payment that will be paid to non-senior management employees in May 2011.  However, we do not have any obligation, nor do we expect to pay any amounts related to these compensation expenses, and since we will not be responsible for paying these expenses, we recognized the amounts allocated to us as both an expense on our income statement and a contribution to “Total Partners’ Capital” on our balance sheet.

 

Derivative Counterparties

 

As a result of KMI’s going-private transaction in May 2007, a number of individuals and entities became significant investors in KMI, and by virtue of the size of its ownership interest in KMI, one of those investors—Goldman Sachs Capital Partners and certain of its affiliates—remains a “related party” (as that term is defined in authoritative accounting literature) to us as of March 31, 2011.  Goldman Sachs has also acted in the past, and may act in the future, as an underwriter for equity and/or debt issuances for us, and Goldman Sachs effectively owned 49% of the terminal assets we acquired from US Development Group LLC in January 2010.

 

In addition, we conduct energy 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, and 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.  The hedging facility 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 created both amounts receivable from and payable to Goldman Sachs affiliates.

 

The following table summarizes the fair values of our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with J. Aron & Company/Goldman Sachs; and (ii) included within “Fair value of derivative contracts” on our accompanying consolidated balance sheets as of March 31, 2011 and December 31, 2010 (in millions):

 

 

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		March 31, 2011				December 31, 2010
Derivatives – asset/(liability)
Current assets		$	3.7			$	-
Noncurrent assets		$	3.7			$	12.7
Current liabilities		$	(281.4	)		$	(221.4	)
Noncurrent liabilities		$	(86.9	)		$	(57.5	)

For more information on our risk management activities see Note 6.

 

Other

 

Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders.  Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors.  KMI indirectly owns all the common stock of our general partner, and the officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the owners of KMI.  Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.

 

The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.  The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties.  The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders.  The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.

 

For a more complete discussion of our related party transactions, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the assets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 to our consolidated financial statements included in our 2010 Form 10-K/A.

 

 

10.  Litigation, Environmental and Other Contingencies

 

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during the three months ended March 31, 2011.  Additional information with respect to these proceedings can be found in Note 16 to our consolidated financial statements that were included in our 2010 Form 10-K/A.  This note also contains a description of any material legal proceedings that were initiated against us during the three months ended March 31, 2011, and a description of any material events occurring subsequent to March 31, 2011 but before the filing of this report.

 

In this note, we refer to our subsidiary SFPP, L.P. as SFPP; our subsidiary Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; BP West Coast Products, LLC as BP; ConocoPhillips Company as ConocoPhillips; Tesoro Refining and Marketing Company as Tesoro; Western Refining Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; our subsidiary Kinder Morgan CO 2 Company, L.P. (the successor to Shell CO 2 Company, Ltd.) as Kinder Morgan CO 2 ; the United States Court of Appeals for the District of Columbia Circuit as the D.C. Circuit; the Federal Energy Regulatory Commission as the FERC; the California Public Utilities Commission as the CPUC; the Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR;  the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; our subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; our subsidiary Kinder Morgan Interstate Gas Transmission LLC as KMIGT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation.  “OR” dockets designate complaint proceedings, and “IS” dockets designate protest proceedings.

 

 

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Federal Energy Regulatory Commission Proceedings

 

The tariffs and rates charged by SFPP and Calnev are subject to a number of ongoing proceedings at the FERC, including the shippers' complaints and protests regarding interstate rates on the pipeline systems listed below.  In general, these complaints and protests 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 complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward.  These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.

 

The issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates.

 

SFPP

 

Pursuant to FERC approved settlements, SFPP settled with eleven of twelve shipper litigants in May 2010 and with Chevron on March 15, 2011 a wide range of rate challenges dating back to 1992 (Historical Cases Settlements).  Settlement payments were made to Chevron in March 2011 and the following FERC dockets that were pending only as to Chevron were resolved: FERC Docket Nos. OR92-8, et al.; OR96-2, et al.; OR02-4; OR03-5; OR07-4; OR09-8 (consolidated); IS98-1; IS05-230; IS07-116; IS08-137;  IS08-302; and IS09-375.  The following appellate review proceedings that were pending before the D.C. Circuit only as to Chevron were also resolved: D.C. Circuit Case Nos. 03-1183; 06-1017 and 06-1128.  In connection with the Historical Cases Settlements, the FERC issued an order directing SFPP to pay refunds to non-litigant shippers and to collect overpaid refunds from non-litigant shippers.  The Historical Cases Settlements resolved all but two of the cases outstanding between SFPP and the twelve litigant shippers, and SFPP does not expect any material adverse impacts from the remaining two unsettled cases.

 

The Historical Cases Settlements and other legal reserves related to SFPP rate litigation resulted in a $172.0 million charge to earnings in 2010.  In June 2010, we made settlement payments of $206.3 million to eleven of the litigant shippers.  Due to this settlement payment and the reserve we took at that time for potential future settlements with Chevron and our CPUC cases described below, a portion of our partnership distributions for the second quarter of 2010 (which we paid in August 2010) was a distribution of cash from interim capital transactions (rather than a distribution of cash from operations).  As a result, our general partner’s cash distributions for the second quarter of 2010 were reduced by $170.0 million.  As provided in our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, our second quarter 2010 interim capital transaction distribution increased our cumulative excess cash coverage (cumulative excess cash coverage is cash from operations generated since our inception in excess of cash distributions paid).  This interim capital transaction also allowed us to resolve the Chevron cases and should allow us to resolve the CPUC rate cases (discussed below) without impacting future distributions.  For more information on our partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions” to our consolidated financial statements included in our 2010 Form 10-K/A.

 

The following FERC dockets, which pertain to all protesting shippers, are currently pending:

 

▪

FERC Docket No. IS08-390 (West Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Status: FERC order issued on February 17, 2011.  While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues.  Subsequently, SFPP made a compliance filing which estimates approximately $16.0 million in refunds.  However, SFPP also filed a rehearing request on certain adverse rulings in the FERC order.  It is not possible to predict the outcome of the FERC review of the rehearing request or appellate review of this order; and

 

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FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, Western Refining, and Southwest Airlines—Status: Initial decision issued on February 10, 2011.  A FERC administrative law judge generally made findings adverse to SFPP, found that East Line rates should have been lower, and recommended that SFPP pay refunds for alleged over-collections.  SFPP has filed a brief with the FERC taking exception to these and other portions of the initial decision.  The FERC will review the initial decision, and while the initial decision is inconsistent with a number of the issues ruled on in FERC’s February 17, 2011 order in Docket No. IS08-390, it is not possible to predict the outcome of FERC or appellate review.

 

 

 

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Calnev

 

On March 17, 2011, the FERC issued an order consolidating the following proceedings and setting them for hearing.  The FERC further held the hearing proceedings in abeyance to allow for settlement judge proceedings:

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FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status:  Before a FERC settlement judge; and

 

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FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev Rates)—Complainants: Tesoro/BP—Status:  Before a FERC settlement judge.

The following docket is currently pending:

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FERC Docket No. IS09-377 (2009 Index Rate Increases)—Protestants: BP, Chevron, and Tesoro—Status:  Requests for rehearing of FERC dismissal pending before FERC.

 

Trailblazer Pipeline Company LLC

 

On July 7, 2010, our subsidiary Trailblazer Pipeline Company LLC refunded a total of approximately $0.7 million to natural gas shippers covering the period January 1, 2010 through May 31, 2010 as part of a settlement reached with shippers to eliminate the December 1, 2009 rate filing obligation contained in its Docket No. RP03-162 rate case settlement.  As part of the agreement with shippers, Trailblazer commenced billing reduced tariff rates as of June 1, 2010 with an additional reduction in tariff rates that took effect January 1, 2011.

 

Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding

 

On November 18, 2010, our subsidiary KMIGT was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act.  The proceeding set for hearing a determination of whether KMIGT’s current rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable.  The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for KMIGT.  A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in rates charged customers by KMIGT can only occur after the FERC has issued a final order.  Prior to that, an administrative law judge presides over an evidentiary hearing and makes an initial decision (which the FERC has directed to be issued within 47 weeks).  On March 23, 2011 the Chief Judge suspended the procedural schedule in this proceeding because all parties have reached a settlement in principle that will resolve all issues set for hearing.  The settlement, which is supported or not opposed by all parties of record, is currently estimated to be filed with the Chief Judge in the first week of May 2011.   If accepted by the administrative law judge , the settlement is subject to approval by the FERC before any rate change is effective.

 

California Public Utilities Commission Proceedings

 

SFPP has previously reported ratemaking and complaint proceedings pending with the CPUC.  The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services.  These matters have been consolidated and assigned to two administrative law judges. 

 

On April 6, 2010, a CPUC administrative law judge issued a proposed decision in several intrastate rate cases involving SFPP and a number of its shippers.  The proposed decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance and allocation of environmental expenses, that we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines.  Moreover, the proposed decision orders refunds relating to these issues where the underlying rates were previously deemed reasonable by the CPUC, which we believe to be contrary to California law.  Based on our review of these CPUC proceedings, we estimate that our maximum exposure is approximately $220 million in reparation and refund payments and if the determinations made in the proposed decision were applied prospectively in two pending cases this could result in approximately $30 million in annual rate reductions.

 

 

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The proposed decision is advisory in nature and can be rejected, accepted or modified by the CPUC.  SFPP filed comments on May 3, 2010 outlining what it believes to be the errors in law and fact within the proposed decision, and on May 5, 2010, SFPP made oral arguments before the full CPUC.  On November 12, 2010, an alternate proposed decision was issued.  The matter remains pending before the CPUC, which may act at any time at its scheduled bimonthly meetings.  Further procedural steps, including motions for rehearing and writ of review to California’s Court of Appeals, will be taken if warranted.  We do not expect the final resolution of this matter to have an adverse effect on our financial position or on our results of operations for 2011.

 

Carbon Dioxide Litigation

 

CO 2 Claims Arbitration

 

Kinder Morgan CO 2 and Cortez Pipeline Company were among the named defendants in CO 2 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 plaintiffs in the arbitration 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 plaintiffs 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 plaintiffs initiated a second arbitration (CO 2 Committee, Inc. v. Shell CO 2 Company, Ltd., aka Kinder Morgan CO 2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO 2 and an ExxonMobil entity.  The second arbitration asserts claims similar to those asserted in the first arbitration.  A second arbitration panel has convened and a final hearing on the parties’ claims and defenses is expected to occur in 2011.

Colorado Severance Tax Assessment

 

On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to Kinder Morgan CO 2 .  The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO 2 with respect to carbon dioxide produced from the McElmo Dome unit for tax years 2005, 2006, and 2007.  The total amount of tax assessed was $5.7 million, plus interest of $1.0 million, plus penalties of $1.7 million.  Kinder Morgan CO 2 protested the Notices of Deficiency and paid the tax and interest under protest.  Kinder Morgan CO 2 is now awaiting the Colorado Department of Revenue’s response to the protest.

 

Montezuma County, Colorado Property Tax Assessment

 

In November of 2009, the County Treasurer of Montezuma County, Colorado, issued to Kinder Morgan CO 2 , as operator of the McElmo Dome unit, retroactive tax bills for tax year 2008, in the amount of $2 million.  Of this amount, 37.2% is attributable to Kinder Morgan CO 2 ’s interest.  The retroactive tax bills were based on the assertion that a portion of the actual value of the carbon dioxide produced from the McElmo Dome unit was omitted from the 2008 tax roll due to an alleged over statement of transportation and other expenses used to calculate the net taxable value.   Kinder Morgan CO 2 paid the retroactive tax bills under protest and will file petitions for refunds of the taxes paid under protest and will vigorously contest Montezuma County’s position.

 

Other

 

In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO 2 ’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing.  These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado.

 

 

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Commercial Litigation Matters

 

Union Pacific Railroad Company Easements

 

SFPP and 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 by the end of the second quarter of 2011, with a decision from the judge expected by the end of 2011.

 

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 appealed this decision, and in December 2008, the appellate court affirmed the decision.  In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards in determining when relocations are necessary and in completing relocations.  Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations.

 

Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP.  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.

 

Severstal Sparrows Point Crane Collapse

 

On June 4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC and located in Sparrows Point, Maryland collapsed while being operated by KMBT.  According to our investigation, the collapse was caused by unexpected, sudden and extreme winds.  On June 24, 2009, Severstal filed suit against KMBT in the United States District Court for the District of Maryland, cause no. WMN 09CV1668.  Severstal alleges that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse.  Severstal seeks unspecified damages for value of the crane and lost profits.  KMBT denies each of Severstal’s allegations.

 

JR Nicholls Tug Incident

 

On February 10, 2010, the JR Nicholls , a tugboat operated by one of our subsidiaries, overturned and sank in the Houston Ship Channel.  Five employees were on board and four were rescued, treated and released from a local hospital.  The fifth employee died in the incident.  The U.S. Coast Guard shut down a section of the ship channel for approximately 60 hours.  Approximately 2,200 gallons of diesel fuel was released from the tugboat.  Emergency response crews deployed booms and contained the product, which was substantially cleaned up.  Salvage operations were commenced and the tugboat has been recovered.  A full investigation of the incident is underway.  Our subsidiary J.R. Nicholls LLC filed a limitations action entitled In the Matter of the Complaint of J.R. Nicholls LLC as Owner of the M/V J.R. NICHOLLS For Exoneration From or Limitation of Liability, CA No. 4:10-CV-00449, U.S. District Court, S.D. Tex.  To date, three surviving crew members have filed claims in that action for personal injuries and emotional distress.  On September 15, 2010, our subsidiary KM Ship Channel Services LLC, agreed to pay a civil penalty of $7,500 to the United States Coast Guard for the unintentional discharge of diesel fuel which occurred when the vessel sank.

 

The Premcor Refining Group, Inc. v. Kinder Morgan Energy Partners, L.P. and Kinder Morgan Petcoke, L.P.; Arbitration in Houston, Texas

 

 

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On August 12, 2010, Premcor filed a demand for arbitration against us and our subsidiary Kinder Morgan Petcoke, L.P., collectively referred to as Kinder Morgan, asserting claims for breach of contract.  Kinder Morgan performs certain petroleum coke handling operations at the Port Arthur, Texas refinery that is the subject of the claim.  The arbitration is being administered by the American Arbitration Association in Dallas, Texas.  Premcor alleges that Kinder Morgan breached its contract with Premcor by failing to name Premcor as an additional insured and failing to indemnify Premcor for claims brought against Premcor by PACC.  PACC and Premcor are affiliated companies.  PACC brought its claims against Premcor in a previous separate arbitration seeking to recover damages allegedly suffered by PACC when a pit wall of a coker unit collapsed at a refinery owned by Premcor.  PACC obtained an arbitration award against Premcor in the amount of $50.3 million, plus post-judgment interest.  Premcor is seeking to hold Kinder Morgan liable for the award. Premcor’s claim against Kinder Morgan is based in part upon Premcor’s allegation that Kinder Morgan is responsible to the extent of Kinder Morgan’s alleged proportionate fault in causing the pit wall collapse.  Kinder Morgan denies and is vigorously defending against all claims asserted by Premcor.  The final arbitration hearing is scheduled to begin on August 29, 2011.

 

Mine Safety Matters

 

In the first quarter of 2011, our bulk terminals operations that handle coal received ten citations under the Mine Safety and Health Act of 1977 which were deemed to be significant and substantial violations of mandatory health and safety standards under section 104 of the act (one of which was under section 104(d) of the act).  To date, the aggregate of proposed assessments received in respect of all citations received under the act in 2011 is $1,117.  We work to promptly abate violations described in the citations.  We do not believe any of such citations or the matters giving rise to such citations will have a material adverse impact on our business, financial position, results of operations or cash flows.

 

Employee Matters

 

James Lugliani vs. Kinder Morgan G.P., Inc. et al. in the Superior Court of California, Orange County

 

James Lugliani, a former Kinder Morgan employee, filed suit in January 2010 against various Kinder Morgan affiliates.  On behalf of himself and other similarly situated current and former employees, Mr. Lugliani claims that the Kinder Morgan defendants have violated the wage and hour provisions of the California Labor Code and Business & Professions Code by failing to provide meal and rest periods; failing to pay meal and rest period premiums; failing to pay all overtime wages due; failing to timely pay wages; failing to pay wages for vacation, holidays and other paid time off; and failing to keep proper payroll records.  We intend to vigorously defend the case.

 

Pipeline Integrity and Releases

 

From time to time, despite our best efforts, our pipelines experience leaks and ruptures.  These leaks and ruptures may cause explosions, fire, and 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.

 

Barstow, California

 

The United States Department of the Navy has alleged that historic releases of methyl tertiary-butyl ether, or MTBE, from Calnev’s Barstow terminal (i) have migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) have impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev; and (iii) could affect the Barstow, California Marine Corps Logistic Base’s water supply system.  Although Calnev believes that it has 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 federal Comprehensive Environmental Response, Compensation and Liability Act (referred to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past response actions. 

 

Westridge Release, 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 our Trans Mountain pipeline system near its Westridge terminal in Burnaby, British Columbia, 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, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the British Columbia Ministry of Environment, the National Energy Board (Canada), and the National Transportation Safety Board (Canada).  Cleanup and environmental remediation is complete, and we have received a British Columbia Ministry of Environment Certificate of Compliance confirming complete remediation.

 

 

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Kinder Morgan Canada, Inc. commenced a lawsuit against the parties it believes were responsible for the third party strike, and a number of other parties have commenced related actions.  All of the outstanding litigation was settled without assignment of fault on April 8, 2011.  Kinder Morgan Canada has recovered the majority of its expended costs in responding to the third party strike.

 

On July 22, 2009, the British Columbia Ministry of Environment issued regulatory charges against the third-party contractor, the engineering consultant to the sewer line project, Kinder Morgan Canada Inc., and our subsidiary Trans Mountain L.P.  The British Columbia Ministry of Environment claims that the parties charged caused the release of crude oil, and in doing so were in violation of various sections of the Environmental, Fisheries and Migratory Bird Act.  A trial has been scheduled to commence in October 2011. We are of the view that the charges have been improperly laid against us, and we continue to vigorously defend against them.

 

Rockies Express Pipeline LLC Indiana Construction Incident

 

In April 2009, Randy Gardner, an employee of Sheehan Pipeline Construction Company (a third-party contractor to Rockies Express and referred to in this note as Sheehan Construction) was fatally injured during construction activities being conducted under the supervision and control of Sheehan Construction.  The cause of the incident was investigated by Indiana OSHA, which issued a citation to Sheehan Construction.  Rockies Express was not cited in connection with the incident.

 

In August 2010, the estate of Mr. Gardner filed a wrongful death action against Rockies Express and several other parties in the Superior Court of Marion County, Indiana, at case number 49D111008CT036870.  The plaintiff alleges that the defendants were negligent in allegedly failing to provide a safe worksite, and seeks unspecified compensatory damages.  Rockies Express denies that it was in any way negligent or otherwise responsible for this incident, and intends to assert 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.

 

General

 

Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability.

 

Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners.  As of March 31, 2011 and December 31, 2010, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $106.0 million and $169.8 million, respectively.  The reserve is primarily related to various claims from regulatory proceedings arising from our West Coast products pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates.  The overall change in the reserve from December 31, 2010 includes a $63.0 million payment (for transportation rate settlements on our Pacific operations’ pipelines) in March 2011 that reduced the liability.  We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

 

Environmental Matters

 

The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC;  California Superior Court, County of Los Angeles, Case No. NC041463.

 

KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles.  The lawsuit was stayed beginning in 2009 and remained stayed through the end of 2010.  A hearing was held on December 13, 2010 to hear the City’s motion to remove the litigation stay.   At the hearing, the judge denied the motion to lift the stay without prejudice. A full litigation stay is in effect until the next case management conference set for June 13, 2011. During the stay, the parties deemed responsible by the local regulatory agency have worked with that agency concerning the scope of the required cleanup and are now starting a sampling and testing program at the site. The local regulatory agency issued specific cleanup goals in early 2010, and two of those parties, including KMLT, have appealed those cleanup goals to the state agency.

 

 

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Plaintiff’s Third Amended Complaint alleges that future environmental cleanup costs at the former terminal will exceed $10 million, and that the plaintiff’s past damages exceed $2 million.  No trial date has yet been set.

 

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

 

On April 23, 2003, Exxon Mobil Corporation 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 Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC.  The terminal is now owned by Plains Products, 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 engaged in court ordered mediation in 2008 through 2009, which did not result in settlement.  The trial judge has issued a Case Management Order and the parties are actively engaged in discovery.

 

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 Corporation and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal.  The complaint was filed in Gloucester County, New Jersey.  Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains seeking to bring Support Terminals/Plains into the case.  Support Terminals/Plains filed motions to dismiss the third party complaints, which were denied.  Support Terminals/Plains is now joined in the case, and it filed an Answer denying all claims.  The court has consolidated the two cases.  All private parties and the state participated in two mediation conferences in 2010.

 

In December 2010, KMLT and Plains Products entered into an agreement in principle with the New Jersey Department of Environmental Protection for settlement of the state’s alleged natural resource damages claim. Currently, a Consent Judgment is being finalized subject to public notice and comment and court approval. The tentative natural resource damage settlement includes a monetary award of $1.1 million and a series of remediation and restoration activities at the terminal site.  KMLT and Plains Products have joint responsibility for this settlement.  Currently, KMLT and Plains Products are working on a settlement agreement that will determine each parties’ relative share of responsibility to the NJDEP under the Consent Judgment noted above. We anticipate a final Consent Judgment during second quarter 2011. The settlement with the state does not resolve the original complaint brought by Exxon Mobil. There is no trial date set.

 

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 us 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, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB.  The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property.  Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.

 

According to the Court’s most recent Case Management Order of January 6, 2011, the parties must complete all fact discovery by June 24, 2011 and all expert witness discovery by August 29, 2011. A mandatory settlement conference is set for July 6, 2011 and the trial is now set for March 13, 2012. We have been and will continue to aggressively defend this action.   This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. We continue to be in compliance with this agency order as we conduct an extensive remediation effort at the City’s stadium property site.

 

 

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Kinder Morgan, EPA Section 114 Information Request

 

On January 8, 2010, Kinder Morgan Inc., on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express Pipeline LLC, received a Clean Air Act Section 114 information request from the U.S. Environmental Protection Agency, Region V.  This information request requires that the three affiliated companies provide the EPA with air permit and various other information related to their natural gas pipeline compressor station operations in Illinois, Indiana, and Ohio.  The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.

 

Notice of Proposed Debarment

 

In April 2011, we received Notices of Proposed Debarment from the United States Environmental Protection Agency’s Suspension and Debarment Division, referred to in this Note as the EPA SDD.  The Notices propose the debarment of Kinder Morgan Energy Partners, L.P., Kinder Morgan, Inc., Kinder Morgan G.P., Inc., and Kinder Morgan Management, LLC, along with four of our subsidiaries, from participation in future federal contracting and assistance activities.  The Notices allege that certain of the respondents’ past environmental violations indicate a lack of present responsibility warranting debarment.  Our objective is to fully comply with all applicable legal requirements and to operate our assets in accordance with our processes, procedures and compliance plans.  We are performing better than industry averages in our incident rates and in our safety performance, all of which is publicly reported on our website.  We take environmental compliance very seriously, and look forward to demonstrating our present responsibility to the EPA SDD through this administrative process and to resolving this matter in a cooperative fashion.  We do not anticipate that the resolution of this matter will have a material adverse impact on our business, financial position, results of operations or cash flows.

 

Other Environmental

 

We are subject to environmental cleanup and enforcement actions from time to time.  In particular, the CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs.  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 under the terms of authority of those laws, 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 alleged violations of environmental and safety regulations.  As we receive notices of non-compliance, we negotiate and settle these matters.  We do not believe that these alleged violations will have a material adverse effect 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.  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.

 

 

 

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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 March 31, 2011, we have accrued an environmental reserve of $74.2 million, and we believe that these pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations.  In addition, as of March 31, 2011, we have recorded a receivable of $7.4 million for expected cost recoveries that have been deemed probable.  As of December 31, 2010, our environmental reserve totaled $74.7 million and our estimated receivable for environmental cost recoveries totaled $8.6 million.  Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.

 

Other

 

We are a defendant in various lawsuits arising from the day-to-day operations of our businesses.  Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, 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.

 

 

11.  Regulatory Matters

 

Natural Gas Pipeline Expansion Filings

 

Kinder Morgan Interstate Gas Transmission Pipeline – Franklin to Hastings Expansion Project

 

KMIGT has filed a prior notice request to expand and replace certain mainline pipeline facilities to create up to 10,000 dekatherms per day of firm transportation capacity to serve an ethanol plant located near Aurora, Nebraska.  The estimated cost of the proposed facilities is $18.6 million.  The project was constructed and went into service on April 14, 2011.

 

Trailblazer Pipeline - Order Rejecting Tariff Record and Denying Waiver

 

On April 28, 2011, the FERC issued an Order Rejecting Tariff Record and Denying Waiver in Trailblazer Pipeline Company LLC’s annual fuel tracker filing at Docket No. RP11-1939-000.  The order requires Trailblazer to make a compliance filing for its annual Expansion Fuel Adjustment Percentage (EFAP) pursuant to its tariff.  In the past two annual tracker filings, Trailblazer received authorization by the FERC to defer collection of its fuel deferred account until a future period by granting a waiver of various fuel tracker provisions.  In its most recent annual filing, Trailblazer again asked for tariff waivers that would defer the collection of its fuel deferred account to a future period, which the FERC denied.  The effect of the FERC denying Trailblazer’s request for the tariff waivers is that Trailblazer must file a revised EFAP that reflects a fuel rate that is required for Trailblazer to collect both its current and deferred fuel costs from shippers.  Certain shippers under their interpretation of their contracts have claimed that they are not required to contribute fuel in-kind in excess of fuel caps contained in their respective negotiated rate agreements.  If the shippers are successful, Trailblazer will be at risk for the recovery of a portion of its fuel costs.  We do not expect this matter to have a material adverse impact on our business, financial position, results of operations or cash flows.

 

Products Pipelines and Natural Gas Pipelines Regulatory Proceedings

 

For information on our pipeline regulatory proceedings, see Note 10 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings” and “—California Public Utilities Commission Proceedings.”

 

 

12.  Recent Accounting Pronouncements

 

Accounting Standards Updates

 

None of the Accounting Standards Updates that we adopted and that became effective January 1, 2011 had a material impact on our consolidated financial statements.

 

 

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

 

General and Basis of Presentation

 

The following information should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); and (ii) our consolidated financial statements, related notes and management’s discussion and analysis of financial condition and results of operations included in our 2010 Form 10-K.

 

 

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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.  Many of our operations are regulated by various U.S. and Canadian regulatory bodies and a portion of our business portfolio (including our Kinder Morgan Canada business segment, the Canadian portion of our Cochin Pipeline, and our bulk and liquids terminal facilities located in Canada) uses the local Canadian dollar as the functional currency for its Canadian operations and enters into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S: Canadian dollar exchange rates.  To help understand our reported operating results, all of the following references to “foreign currency effects” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar.  The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants.

 

The profitability of our refined petroleum products pipeline transportation business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services.  Transportation volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored.  Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable.  Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers.  The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.

 

With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended 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.  These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and 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.  Similarly, in our Texas Intrastate Pipeline business, we have long-term transport and sales requirements with minimum volume payment obligations which secure approximately 75% of our sales and transport margins in that business.  Therefore, where we have long-term contracts, we are not exposed to short-term changes in commodity supply or demand.  However, as contracts expire, we do have exposure to the longer term trends in supply and demand for natural gas.  As of December 31, 2010, the remaining average contract life of our natural gas transportation contracts (including our intrastate pipelines) was approximately nine years.

 

Our CO 2 sales and transportation business, like our natural gas pipelines business, has primarily fixed fee contracts with minimum volume requirements, which as of December 31, 2010, had a remaining average contract life of 4.7 years.  On a volume-weighted basis, approximately 76% of our contractual volumes are based on a fixed fee, and 24% fluctuates with the price of oil.  In the long-term, our success in this business is driven by the demand for carbon dioxide.  However, short-term changes in the demand for carbon dioxide typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. In our CO 2 segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add.  In that regard, our production during any period is an important measure.  In addition, the revenues we receive from our crude oil, natural gas liquids and carbon dioxide 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, 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 derivative contracts, particularly for crude oil.  Our realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $68.78 per barrel in the first quarter of 2011, and $60.50 per barrel in the first quarter of 2010.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $90.76 per barrel in the first quarter of 2011, and $76.42 per barrel in the first quarter of 2010.

 

 

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The factors impacting our Terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored.  As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, 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.  While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel.  For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums.  Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions.  Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity.  Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand.  Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which is typically approximately three to four years), 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 (see “—Results of Operations” below), 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.  Continuing our history of making accretive acquisitions and economically advantageous expansions of existing businesses, in the full year 2010, we invested approximately $2.5 billion for both strategic business acquisitions and expansions of existing assets, and in the first quarter of 2011, we invested an additional $65.9 million.  Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 4.8%, 8.1%, and 7.0%, respectively, for the one-year, three-year, and five-year periods ended December 31, 2010.

 

Thus, the amount that we are able to increase distributions to our unitholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions.  We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $1.4 billion for our 2011 capital expansion program, including small acquisitions and investment contributions.  Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict.

 

Our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control.  Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.

 

In addition, our ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions.  As a master limited partnership, we distribute all of our available cash and we access capital markets to fund acquisitions and asset expansions.  Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required.  For a further discussion of our liquidity, including our public debt and equity offerings in the first quarter of 2011, please see “—Financial Condition” below.

 

Critical Accounting Policies and Estimates

 

Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles in the United States involves the exercise of varying degrees of judgment.  Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared.  These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.  We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances.  Nevertheless, actual results may differ significantly from our estimates, and 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.

 

 

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Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in our 2010 Form 10-K.  There have not been any significant changes in these policies and estimates during the three months ended March 31, 2011.  Furthermore, with regard to our goodwill impairment testing, there has been no change during the three months ended March 31, 2011 indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.

 

Results of Operations

 

Consolidated

 

		Three Months Ended March 31,								Earnings
		2011				2010				increase/(decrease)
		(In millions, except percentages)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
Products Pipelines(b)		$	180.5			$	6.4			$	174.1				2,720	%
Natural Gas Pipelines(c)			222.6				220.6				2.0				1	%
CO 2 (d)			262.0				253.2				8.8				3	%
Terminals(e)			174.4				150.5				23.9				16	%
Kinder Morgan Canada			47.9				45.0				2.9				6	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments			887.4				675.7				211.7				31	%
Depreciation, depletion and amortization expense			(221.8	)			(227.3	)			5.5				2	%
Amortization of excess cost of equity investments			(1.5	)			(1.4	)			(0.1	)			(7	)%
General and administrative expense(f)			(189.2	)			(101.1	)			(88.1	)			(87	)%
Unallocable interest expense, net of interest income(g)			(131.7	)			(116.3	)			(15.4	)			(13	)%
Unallocable income tax expense			(2.3	)			(2.2	)			(0.1	)			(5	)%
Net income			340.9				227.4				113.5				50	%
Net income attributable to noncontrolling interests(h)			(3.1	)			(2.1	)			(1.0	)			(48	)%
Net income attributable to Kinder Morgan Energy Partners, L.P.		$	337.8			$	225.3			$	112.5				50	%

____________

(a)	Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income).  Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)	2011 amount includes a $0.2 million increase in income from unrealized foreign currency gains on long-term debt transactions.  2010 amount includes a $158.0 million increase in expense associated with rate case liability adjustments, and a $0.5 million increase in income resulting from unrealized foreign currency gains on long-term debt transactions.
(c)	2010 amount includes a $0.9 million unrealized gain on derivative contracts used to hedge forecasted natural gas sales, and a $0.4 million increase in income from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition.
(d)	2011 and 2010 amounts include increases in income of $3.7 million and $5.4 million, respectively, from unrealized gains on derivative contracts used to hedge forecasted crude oil sales.
(e)	2011 amount includes (i) a $4.5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (ii) a $2.2 million increase in income from adjustments associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; (iii) a $2.0 million increase in expense from casualty insurance deductibles and the write-off of assets related to casualty losses; and (iv) a $0.6 million increase in expense associated with the settlement of a litigation matter at our Carteret, New Jersey liquids terminal.  2010 amount includes a $0.4 million increase in expense related to storm and flood clean-up and repair activities.
(f)	Includes unallocated litigation and environmental expenses.  2011 amount includes (i) a combined $89.9 million increase in non-cash compensation expense, allocated to us from KMI (including $87.1 million related to a special bonus expense to non-senior management employees; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense); and (ii) a $0.5 million increase in expense for certain asset and business acquisition costs.  2010 amount includes (i) a $1.6 million increase in legal expense associated with items disclosed in these footnotes such as legal settlements and pipeline failures;  (ii) a $1.4 million increase in non-cash compensation expense, allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (iii) a $1.4 million increase in expense for certain asset and business acquisition costs; and (iv) a $0.3 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.
(g)	2011 and 2010 amounts include increases in imputed interest expense of $0.2 million and $0.4 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
(h)	2011 and 2010 amounts include decreases of $1.1 million and $2.3 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2011 and 2010 items previously disclosed in these footnotes.

 

 

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Net income attributable to our partners—including all of our limited partner unitholders and our general partner—totaled $337.8 million for the three months ended March 31, 2011.  This compares to net income attributable to our partners of $225.3 million for the first quarter of 2010.  Total revenues for the comparable first quarter periods were $1,992.8 million in 2011 and $2,129.6 million in 2010.

 

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

 

For the comparable first quarter periods, total segment earnings before depreciation, depletion and amortization expenses increased $211.7 million (31%) in 2011; however, this overall increase in earnings included an increase of $159.2 million from the effect of the certain items described in the footnotes to the table above (which combined to increase total segment EBDA by $8.0 million in the first quarter of 2011 and to decrease total segment EBDA by $151.2 million in the first quarter of 2010).  The remaining $52.5 million (6%) increase in quarterly segment earnings before depreciation, depletion and amortization resulted from better performance from all five of our reportable business segments, mainly due to increases attributable to our Terminals, Products Pipelines, and CO 2 business segments.

 

Products Pipelines

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except operating statistics and percentages)
Revenues		$	225.6			$	207.5			$	18.1				9	%
Operating expenses(a)			(52.3	)			(208.9	)			156.6				75	%
Other income			0.1				-				0.1				n/a
Earnings from equity investments			10.9				5.8				5.1				88	%
Interest income and Other, net(b)			1.3				2.6				(1.3	)			(50	)%
Income tax expense			(5.1	)			(0.6	)			(4.5	)			(750	)%
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	180.5			$	6.4			$	174.1				2,720	%
Gasoline (MMBbl)(c)			95.9				93.8				2.1				2	%
Diesel fuel (MMBbl)			36.6				32.8				3.8				12	%
Jet fuel (MMBbl)			25.6				24.8				0.8				3	%
Total refined product volumes (MMBbl)			158.1				151.4				6.7				4	%
Natural gas liquids (MMBbl)			6.6				5.9				0.7				12	%
Total delivery volumes (MMBbl)(d)			164.7				157.3				7.4				5	%
Ethanol (MMBbl)(e)			7.3				7.2				0.1				1	%

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(a)	2010 amount includes a $158.0 million increase in expense associated with rate case liability adjustments.
(b)	2011 and 2010 amounts include increases in income of $0.2 million and $0.5 million, respectively, resulting from unrealized foreign currency gains on long-term debt transactions.
(c)	Volumes include ethanol pipeline volumes.
(d)	Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.
(e)	Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

For the comparable first quarter periods, the certain items related to our Products Pipelines business segment and described in the footnotes to the table above accounted for a $157.7 million increase in earnings before depreciation, depletion and amortization expenses in 2011 versus 2010 (combining to increase EBDA by $0.2 million in the first quarter of 2011 and to decrease EBDA by $157.5 million in the first quarter of 2010).  Following is information related to the increases and decreases in the segment’s (i) remaining $16.4 million (10%) increase in earnings before depreciation, depletion and amortization; and (ii) $18.1 million (9%) increase in operating revenues:

 

Three months ended March 31, 2011 versus Three months ended March 31, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Cochin Pipeline		$	7.0				80	%		$	9.7				94	%
Pacific operations			4.3				6	%			2.1				2	%
Southeast Terminals			2.7				17	%			4.0				18	%
Plantation Pipeline			2.5				24	%			-				-
West Coast Terminals			2.0				11	%			3.0				13	%
Calnev Pipeline			(1.8	)			(12	)%			(1.2	)			(7	)%
All others (including eliminations)			(0.3	)			(1	)%			0.5				2	%
Total Products Pipelines		$	16.4				10	%		$	18.1				9	%

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in the first quarter of 2011 compared to the first quarter of 2010 were attributable to the following:

 

▪

a $7.0 million (80%) increase in earnings from our Cochin natural gas liquids pipeline system.  The increase was chiefly due to a $9.7 million (94%) increase in operating revenues, driven by an overall 77% increase in throughput volumes .  The increase in delivery volume in the first quarter of 2011 was system-wide—West leg (U.S.) volumes increased due to a higher demand for liquids products related to colder winter weather, and East leg (Canadian) volumes increased due to both an additional shipper and to the exercise of a certain shipper incentive tariff offered in the first quarter of 2011 ;

 

▪

a $4.3 million (6%) increase in earnings from our Pacific operations—consisting of a $2.1 million (2%) increase from higher operating revenues and a $2.3 million (9%) increase due to lower combined operating expenses.  The increase in revenues was driven by a $3.3 million (12%) increase in fee-based terminal revenues, mainly attributable to a 5% increase in ethanol handling volumes that were due in part to mandated increases in ethanol blending rates in California since the beginning of 2010.  The increase in earnings due to lower operating expenses was largely due to incremental product gains of $1.7 million;

 

▪

a $2.7 million (17%) increase in earnings from our Southeast terminal operations—due primarily to higher product inventory gains relative to the first quarter of 2010;

 

▪

a $2.5 million (24%) increase in earnings from our 51%-owned Plantation Pipe Line Company—due to higher net income earned by Plantation in the first quarter of 2011.  The increase in Plantation’s earnings was largely associated with both an absence of an expense from the write-off of an uncollectible receivable in the first quarter of 2010, and higher transportation revenues associated with an 18% increase in product delivery volumes;

 

▪

a $2.0 million (11%) increase in earnings from our West Coast terminal operations—mainly due to higher revenues at our combined Carson/Los Angeles Harbor terminal resulting from the completion of various terminal expansion projects that increased liquids tank capacity since the end of the first quarter of 2010; and

 

▪

a $1.8 million (12%) decrease in earnings from our Calnev Pipeline—mainly due to a $1.2 million (7%) drop in revenues largely associated with a 14% decrease in ethanol handling volumes relative to the first quarter of 2010.  The decrease in volumes was due both to lower deliveries to the Las Vegas market, and to ethanol blending services offered by a competing terminal.

 

 

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Natural Gas Pipelines

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except operating statistics and percentages)
Revenues(a)		$	1,019.4			$	1,236.7			$	(217.3	)			(18	)%
Operating expenses(b)			(843.7	)			(1,051.5	)			207.8				20	%
Earnings from equity investments			47.1				33.8				13.3				39	%
Interest income and Other, net			1.1				2.2				(1.1	)			(50	)%
Income tax expense			(1.3	)			(0.6	)			(0.7	)			(117	)%
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	222.6			$	220.6			$	2.0				1	%
Natural gas transport volumes (Bcf)(c)			694.4				632.3				62.1				10	%
Natural gas sales volumes (Bcf)(d)			191.2				189.0				2.2				1	%

____________

(a)	2010 amount includes a $0.4 million increase in revenues from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition.
(b)	2010 amount includes unrealized gains of $0.9 million on derivative contracts used to hedge forecasted natural gas sales.
(c)	Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC and Texas intrastate natural gas pipeline group, and for 2011 only, Fayetteville Express Pipeline LLC pipeline volumes.
(d)	Represents Texas intrastate natural gas pipeline group volumes.

For the comparable first quarter periods, the certain items related to our Natural Gas Pipelines business segment and described in the footnotes to the table above accounted for both a $1.3 million decrease in earnings before depreciation, depletion and amortization expenses and a $0.4 million decrease in revenues in 2011 versus 2010.  Following is information related to the increases and decreases in the segment’s remaining (i) $3.3 million (2%) increase in earnings before depreciation, depletion and amortization; and (ii) $216.9 million (18%) decrease in operating revenues:

 

Three months ended March 31, 2011 versus Three months ended March 31, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
KinderHawk Field Services(a)		$	9.7				n/a			$	n/a				n/a
Midcontinent Express Pipeline(a)			4.8				87	%			n/a				n/a
Casper and Douglas Natural Gas Processing			2.8				57	%			1.6				5	%
Texas Intrastate Natural Gas Pipeline Group			2.6				3	%			(210.7	)			(19	)%
Kinder Morgan Interstate Gas Transmission			(10.6	)			(34	)%			(7.1	)			(18	)%
Rockies Express Pipeline(a)			(2.3	)			(11	)%			n/a				n/a
Trailblazer Pipeline			(2.0	)			(16	)%			(0.1	)			(1	)%
All others (including eliminations)			(1.7	)			(4	)%			(0.6	)			(1	)%
Total Natural Gas Pipelines		$	3.3				2	%		$	(216.9	)			(18	)%

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(a)	Equity investments.  We record earnings under the equity method of accounting, but we receive distributions in amounts essentially equal to equity earnings plus depreciation and amortization expenses less sustaining capital expenditures.

The overall increase in our Natural Gas Pipelines segment’s earnings before depreciation, depletion and amortization expenses in the first quarter of 2011 compared to the first quarter of 2010 was due primarily to the following:

 

▪

incremental equity earnings from our 50%-owned KinderHawk Field Services LLC, which we acquired on May 21, 2010;

 

▪

incremental equity earnings from our 50%-owned Midcontinent Express natural gas pipeline system, due primarily to the June 2010 completion of two natural gas compression projects that increased the system’s Zone 1 transportation capacity from 1.5 billion to 1.8 billion cubic feet per day, and Zone 2 capacity from 1.0 billion to 1.2 billion cubic feet per day;

 

▪

an increase of $2.8 million (57%) from our Casper Douglas gas processing operations, primarily attributable to higher natural gas processing spreads;

 

▪

an increase of $2.6 million (3%) from our Texas intrastate natural gas pipeline group, due largely to higher sales and storage margins;

 

▪

a decrease of $10.6 million (34%) from our Kinder Morgan Interstate Gas Transmission pipeline system, driven by a $4.2 million decrease from lower pipeline net fuel recoveries, and a $4.0 million decrease from lower natural gas transportation and storage services.  Both decreases in earnings were due in part to a 9% drop in system-wide transportation volumes in the first quarter of 2011, due mainly to a negative impact on long-haul deliveries resulting from unfavorable basis differentials;

 

▪

a decrease of $2.3 million (11%) from our 50%-owned Rockies Express pipeline system, reflecting lower net income earned by Rockies Express Pipeline LLC.  The decrease in Rockies Express’s earnings was largely due to (i) higher interest expense associated with the securing of permanent financing for its pipeline construction costs (Rockies Express Pipeline LLC issued $1.7 billion aggregate principal amount of fixed rate senior notes in a private offering in March 2010); and (ii) higher expenses associated with the write-off of certain transportation fuel recovery receivables pursuant to a contractual agreement; and

 

▪

a decrease of $2.0 million (16%) from our Trailblazer pipeline system, mainly attributable to unfavorable cashouts on operating balancing agreements, and partly attributable to both lower base rates as a result of rate case settlements made since the end of the first quarter of 2010, and lower backhaul transportation services relative to the first quarter of 2010.

 

The overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) in the comparable three month periods of 2011 and 2010 primarily relate to the natural gas purchase and sale activities of our Texas intrastate natural gas pipeline group, with the variances from period-to-period in both revenues and operating expenses mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold.  Our intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its gas sales revenues are largely offset by corresponding increases and decreases in its gas purchase costs.  In the comparable first quarter periods of 2011 and 2010, our Texas intrastate natural gas pipeline group accounted for 88% and 90%, respectively, of the segment’s revenues, and 94% and 96%, respectively, of the segment’s operating expenses.

 

 

 

 

 

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CO 2

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except operating statistics and percentages)
Revenues(a)		$	340.8			$	321.8			$	19.0				6	%
Operating expenses			(83.6	)			(79.1	)			(4.5	)			(6	)%
Earnings from equity investments			5.8				6.5				(0.7	)			(11	)%
Other, net			0.1				-				0.1				n/a
Income tax (expense) benefit			(1.1	)			4.0				(5.1	)			(128	)%
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	262.0			$	253.2			$	8.8				3	%
Southwest Colorado carbon dioxide production (gross)(Bcf/d)(b)			1.3				1.3				-				-
Southwest Colorado carbon dioxide production (net)(Bcf/d)(b)			0.5				0.5				-				-
SACROC oil production (gross)(MBbl/d)(c)			28.9				30.0				(1.1	)			(4	)%
SACROC oil production (net)(MBbl/d)(d)			24.1				25.0				(0.9	)			(4	)%
Yates oil production (gross)(MBbl/d)(c)			21.9				25.6				(3.7	)			(14	)%
Yates oil production (net)(MBbl/d)(d)			9.7				11.4				(1.7	)			(15	)%
Katz oil production (gross)(MBbl/d)(c)			0.2				0.3				(0.1	)			(33	)%
Katz oil production (net)(MBbl/d)(d)			0.2				0.3				(0.1	)			(33	)%
Natural gas liquids sales volumes (net)(MBbl/d)(d)			8.3				9.7				(1.4	)			(14	)%
Realized weighted average oil price per Bbl(e)(f)		$	68.78			$	60.50			$	8.28				14	%
Realized weighted average natural gas liquids price per Bbl(f)(g)		$	60.93			$	55.06			$	5.87				11	%

____________

(a)	2011 and 2010 amounts include unrealized gains of $3.7 million and $5.4 million, respectively, on derivative contracts used to hedge forecasted crude oil sales.
(b)	Includes McElmo Dome and Doe Canyon sales volumes.
(c)	Represents 100% of the production from the field.  We own an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit.
(d)	Net to us, after royalties and outside working interests.
(e)	Includes all of our crude oil production properties.
(f)	Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
(g)	Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Our CO 2 segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO 2 ) and crude oil, and the production and marketing of natural gas and natural gas liquids.   We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and Sales and Transportation Activities.

 

For the comparable first quarter periods, the certain items related to unrealized gains on our derivative contracts described in footnote (a) to the table above increased revenues and earnings before depreciation, depletion and amortization by $3.7 million in the first quarter of 2011 and by $5.4 million in the first quarter of 2010.  The quarter-to-quarter decrease in the certain items accounted for a $1.7 million decrease for the first quarter of 2011 in both segment revenues and segment earnings before depreciation, depletion and amortization expenses when compared to the first quarter of 2010.  For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three month periods of 2011 and 2010, in the segment’s remaining (i) $10.5 million (4%) increase in earnings before depreciation, depletion and amortization; and (ii) $20.7 million (7%) increase in operating revenues:

 

 

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Three months ended March 31, 2011 versus Three months ended March 31, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Oil and Gas Producing Activities		$	5.3				3	%		$	11.9				5	%
Sales and Transportation Activities			5.2				8	%			13.9				19	%
Intrasegment eliminations			-				-				(5.1	)			(41	)%
Total CO 2		$	10.5				4	%		$	20.7				7	%

The $5.3 million (3%) increase in earnings in the first quarter of 2011 from the segment’s oil and gas producing activities, which include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants, was due to the following:

 

▪

an increase of $11.9 million (5%) due to higher operating revenues, driven by an $11.2 million (6%) increase in crude oil sales revenues.  The overall increase in sales revenues was due to higher average realizations for U.S. crude oil (from an average realization of $60.50 per barrel in the first quarter of 2010 compared with $68.78 per barrel in the first quarter of 2011), and was partially offset by a decrease in crude oil sales volumes of 7% (due to a year-over-year decline in production); and

 

▪

a decrease of $6.6 million (9%) due to higher combined operating expenses, driven by a $7.0 million (14%) increase in operating and maintenance expenses resulting from higher carbon dioxide supply expenses, primarily due to initiating carbon dioxide injections into the Katz field, and from higher prices charged by the industry’s material and service providers (for items such as outside services, maintenance, and well workover services), which impacted rig costs, other materials and services, and capital and exploratory costs.

 

The overall $5.2 million (8%) quarter-to-quarter increase in earnings from the segment’s sales and transportation activities in 2011 compared to 2010 was mainly due to the following:

 

▪

an increase of $13.9 million (19%) due to higher combined operating revenues, driven by a $13.0 million (26%) increase in carbon dioxide sales revenues.  Average carbon dioxide sales price increased 25% in the first quarter of 2011 (from $1.00 per thousand cubic feet in first quarter 2010 to $1.25 per thousand cubic feet in first quarter 2011), due largely to the fact that a portion of our carbon dioxide sales contracts are indexed to oil prices which have increased relative to the first quarter of last year;

 

▪

a decrease of $5.1 million (127%) due to higher income tax expenses, due primarily to decreases in expense in the first quarter of 2010 due to favorable Texas margin tax liability adjustments related to the expensing of previously capitalized carbon dioxide costs; and

 

▪

a decrease of $2.9 million (21%) due to higher operating expenses, associated mainly with both higher carbon dioxide supply expenses, and higher labor expenses that resulted from a decrease in the amount of labor capitalized to construction projects when compared to the first quarter of last year.

 

 

 

 

 

 

 

 

 

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Terminals

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except operating statistics and percentages)
Revenues		$	331.7			$	304.1			$	27.6				9	%
Operating expenses(a)			(167.2	)			(155.9	)			(11.3	)			(7	)%
Other income(b)			0.1				1.3				(1.2	)			(92	)%
Earnings from equity investments			2.1				0.2				1.9				950	%
Other, net			0.7				0.9				(0.2	)			(22	)%
Income tax benefit (expense)(c)			7.0				(0.1	)			7.1				n/m
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	174.4			$	150.5			$	23.9				16	%
Bulk transload tonnage (MMtons)(d)			23.7				21.4				2.3				11	%
Ethanol (MMBbl)			15.7				15.5				0.2				1	%
Liquids leaseable capacity (MMBbl)			58.8				57.9				0.9				2	%
Liquids utilization %			94.4	%			96.4	%			(2.0	)%			(2	)%

__________

n/m – not meaningful

(a)	2011 amount includes (i) a combined $1.5 million increase in expense at our Carteret, New Jersey liquids terminal, associated with fire damage and repair activities, and the settlement of a certain litigation matter; (ii) a $0.7 million increase in expense associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; and (iii) a $0.1 million increase in expense associated with the write-off of assets related to casualty losses.  2010 amount includes a $0.4 million increase in expense related to storm and flood clean-up and repair activities.
(b)	2011 amount includes both a $1.0 million gain from adjustments associated with the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009, and a $1.0 million loss from the write-off of assets related to casualty losses.
(c)	2011 amount includes a $4.5 million decrease in expense (reflecting tax savings) related to non-cash compensation expense allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense), and a $1.9 million decrease in expense (reflecting tax savings) related to the net decrease in income from the sale of our ownership interest in the boat fleeting business described in both footnotes (a) and (b) and in Note 3 to our 2010 Form 10-K/A.
(d)	Volumes for acquired terminals are included for both periods.

Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities.   We group our bulk and liquids terminal operations into regions based on geographic location and/or primary operating function.  This structure allows our management to organize and evaluate segment performance and to help make operating decisions and allocate resources.

 

For the comparable first quarter periods, the certain items related to our Terminals business segment and described in the footnotes to the table above accounted for a $4.5 million increase in earnings before depreciation, depletion and amortization expenses in 2011 versus 2010 (combining to increase EBDA by $4.1 million in the first quarter of 2011 and to decrease EBDA by $0.4 million in the first quarter of 2010).

 

In addition, in both 2011 and 2010, we acquired certain terminal assets and businesses in order to gain access to new markets or to complement and/or enlarge our existing terminal operations, and combined, these acquired operations contributed incremental earnings before depreciation, depletion and amortization of $4.0 million, revenues of $4.5 million, operating expenses of $2.2 million, and equity earnings of $1.7 million in the first quarter of 2011.  All of the incremental amounts listed above represent the earnings, revenues and expenses from acquired terminals’ operations during the additional months of ownership in the first quarter of 2011, and do not include increases or decreases during the same months we owned the assets in 2010.  For more information about the terminal assets and operations we acquired in the first quarter of 2011, see Note 2 “Acquisitions, Joint Ventures, and Divestitures—Acquisitions” to our consolidated financial statements included elsewhere in this report.  For more information about our 2010 Terminal acquisitions, see Note 3 “Acquisitions and Divestitures—Acquisitions from Unrelated Entities” to our consolidated financial statements included in our 2010 Form 10-K/A.

 

 

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Following is information, for the comparable three month periods of 2011 and 2010, related to the segment’s remaining (i) $15.4 million (10%) increase in earnings before depreciation, depletion and amortization; and (ii) $23.1 million (8%) increase in operating revenues.  These changes represent increases and decreases in terminal results at various locations for all terminal operations owned during identical periods in both 2011 and 2010.

 

Three months ended March 31, 2011 versus Three months ended March 31, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Gulf Liquids		$	9.0				25	%		$	10.0				21	%
Southeast			2.9				26	%			2.0				8	%
Ethanol			2.3				34	%			1.5				14	%
Mid-Atlantic			2.1				19	%			4.8				19	%
All others (including intrasegment eliminations and unallocated income tax expenses)			(0.9	)			(1	)%			4.8				2	%
Total Terminals		$	15.4				10	%		$	23.1				8	%

The earnings increase from our Gulf Liquids terminals was driven by higher liquids revenues, mainly due to new and renewed customer agreements at higher rates.  Including all terminals, we increased our liquids terminals’ leasable capacity by 0.9 million barrels (1.6%) since the end of the first quarter last year, via both terminal acquisitions and completed terminal expansion projects.

 

The increase in earnings before depreciation, depletion and amortization from our Southeast region terminals was driven by a $2.0 million increase in earnings from our Shipyard River Terminal, located in Charleston, South Carolina.  Shipyard’s earnings increase was driven by a $1.7 million increase in operating revenues, due mostly to higher cement revenue, increased salt handling, and higher storage fees.

 

The increase in earnings from our Ethanol terminals includes (i) incremental earnings of $0.7 million from our unit train terminal facility located in Richmond, California, which began operations in March 2010; and (ii) incremental earnings of $1.4 million from the ethanol handling train terminals we acquired from US Development Group LLC in January 2010 (the operating results for each of these facilities are not included in the incremental amounts from acquired operations described above).

 

The overall increase in earnings from the terminals included in our Mid-Atlantic region was driven by a $3.3 million increase from our Pier IX terminal, located in Newport News, Virginia.  Its earnings increase was driven by higher shipments of coal consistent with the ongoing domestic economic recovery and with growth in the export market due to greater foreign demand for U.S. metallurgical coal.  Coal transload volumes at Pier IX increased 75% in the first quarter of 2011, and for all terminals combined, coal volumes increased 23%, when compared to the first quarter of 2010.

 

 

 

 

 

 

 

 

 

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Kinder Morgan Canada

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except operating statistics and percentages)
Revenues		$	75.6			$	59.8			$	15.8				26	%
Operating expenses			(26.4	)			(19.5	)			(6.9	)			(35	)%
Earnings from equity investments			(1.0	)			0.4				(1.4	)			(350	)%
Interest income and Other, net			3.4				5.8				(2.4	)			(41	)%
Income tax expense			(3.7	)			(1.5	)			(2.2	)			(147	)%
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	47.9			$	45.0			$	2.9				6	%
Transport volumes (MMBbl)(a)			26.7				23.8				2.9				12	%

__________

(a)	Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and our one-third ownership interest in the Express crude oil pipeline system.  For each of the segment’s three primary businesses, following is information related to the increases and decreases, in the comparable three month periods of 2011 and 2010, in the segment’s (i) $2.9 million (6%) increase in earnings before depreciation, depletion and amortization; and (ii) $15.8 million (26%) increase in operating revenues:

 

Three months ended March 31, 2011 versus Three months ended March 31, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Trans Mountain Pipeline		$	4.5				11	%		$	15.7				27	%
Express Pipeline			(1.3	)			(32	)%			n/a				n/a
Jet Fuel Pipeline			(0.3	)			(23	)%			0.1				5	%
Total Kinder Morgan Canada		$	2.9				6	%		$	15.8				26	%

The overall increase in Trans Mountain’s earnings before depreciation, depletion and amortization in the first quarter of 2011 compared to the first quarter of 2010 was driven by higher revenues, primarily due to favorable impacts from a negotiated pipeline toll settlement agreement which became effective on January 1, 2011.    Trans Mountain also reported an overall 12% increase in pipeline throughput volumes, benefitting mostly from higher volumes on its Puget Sound pipeline system, which delivers Canadian crude oil from Trans Mountain’s mainline pipeline at Abbotsford, British Columbia to refineries located in Washington State.

 

The decrease in earnings from our investment in the Express pipeline system related primarily to lower equity earnings as a result of lower net income earned by Express in the first quarter of 2011.   Foreign currency effects—primarily reflecting noncash losses on balance sheet remeasurement—decreased Express’ net income in the first quarter of 2011, compared with the first quarter of 2010.

 

 

 

 

 

 

 

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Other

 

		Three Months Ended March 31,
		2011				2010				increase/(decrease)
		(In millions, except percentages)
General and administrative expenses(a)		$	189.2			$	101.1			$	88.1				87	%
Unallocable interest expense, net of interest income(b)		$	131.7			$	116.3			$	15.4				13	%
Unallocable income tax expense		$	2.3			$	2.2			$	0.1				5	%
Net income attributable to noncontrolling interests(c)		$	3.1			$	2.1			$	1.0				48	%

__________

(a)	Includes such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services.  2011 amount includes (i) a combined $89.9 million increase in non-cash compensation expense, allocated to us from KMI (including $87.1 million related to a special bonus expense to non-senior management employees; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense); and (ii) a $0.5 million increase in expense for certain asset and business acquisition costs.  2010 amount includes (i) a $1.6 million increase in legal expense associated with items disclosed in these footnotes such as legal settlements and pipeline failures;  (ii) a $1.4 million increase in non-cash compensation expense, allocated to us from KMI (we do not have any obligation, nor do we expect to pay any amounts related to this expense); (iii) a $1.4 million increase in expense for certain asset and business acquisition costs; and (iv) a $0.3 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.
(b)	2011 and 2010 amounts include increases in imputed interest expense of $0.2 million and $0.4 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
(c)	2011 and 2010 amounts include decreases of $1.1 million and $2.3 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the three month 2011 and 2010 items previously disclosed in these footnotes.

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

 

For the comparable first quarter periods, the certain items related to our general and administrative expenses described in footnote (a) to the table above accounted for an $86.3 million increase in expense in 2011 versus 2010 (combining to increase general and administrative expenses by $90.4 million in the first quarter of 2011 and to increase general and administrative expenses by $4.1 million in the first quarter of 2010).  The remaining $1.8 million (2%) quarter-to-quarter increase in expense includes increases and decreases in various operational expenses, including (i) higher employee benefit and payroll tax expenses, due mainly to cost inflation increases on work-based health and insurance benefits, higher wage rates and a larger year-over-year labor force; (ii) higher labor expenses, primarily due to a larger year-over-year labor force; and (iii) lower overall corporate insurance expenses, due primarily to higher premium taxes and higher captive insurance adjustments recorded in the first quarter of 2010.

 

In the table above, we report our unallocable interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our total interest expense to arrive at one interest amount, and after taking into effect the certain items described in footnote (b) to the table above, our unallocable interest expense increased $15.6 million (13%) in the first quarter of 2011, when compared with the same quarter a year earlier.  The increase in interest expense was primarily due to a higher average debt balance in the first quarter of 2011, and partly due to a small increase in our weighted average interest rate, when compared to the first quarter last year (from 4.32% during the first quarter of 2010 to 4.44% during the first quarter of 2011).  Our average borrowings for the first quarter of 2011 increased 8% from the comparable prior year period, largely due to the capital expenditures, business acquisitions, and joint venture contributions we have made since the end of the first quarter of 2010.

 

 

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We use interest rate swap agreements to transform a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt, and in periods of rising interest rates, these swaps result in period-to-period increases in our interest expense.  As of March 31, 2011, approximately 49% of our $11,748.8 million consolidated debt balance (excluding the value of interest rate swap agreements) was subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps.  For more information on our interest rate swaps, see Note 6 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements included elsewhere in this report.

 

Financial Condition

 

General

 

As of March 31, 2011, we believe our balance sheet and liquidity position reflected a strong capital base.  Cash and cash equivalents on hand at quarter end was $178.4 million and we had approximately $1.4 billion of borrowing capacity available under our $2.0 billion senior unsecured revolving bank credit facility (discussed below in “—Short-term Liquidity”).  We believe our cash position and our remaining borrowing capacity allow us to manage our day-to-day cash requirements and any anticipated obligations, and currently, we believe our liquidity to be adequate.

 

Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.

 

In general, we expect to fund:

 

▪

cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;

 

▪

expansion capital expenditures and working capital deficits with retained cash (which may result from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), additional borrowings, and the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;

 

▪

interest payments with cash flows from operating activities; and

 

▪

debt principal payments with additional borrowings, as such debt principal payments become due, or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.

 

In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”

 

Credit Ratings and Capital Market Liquidity

 

As part of our financial strategy, we try to maintain an investment-grade credit rating, which involves, among other things, the issuance of additional limited partner units in connection with our acquisitions and expansion activities in order to maintain acceptable financial ratios.   The major debt rating agencies routinely evaluate our outstanding debt, and our cost of borrowing can increase or decrease depending on these debt ratings.   Currently, our long-term corporate debt credit rating is BBB (stable), Baa2 (stable) and BBB (stable), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch Inc., respectively.

 

On February 22, 2011, Moody’s revised its outlook on our long-term credit rating to stable from negative, affirmed our long-term credit rating at Baa2, and upgraded our short-term credit rating to Prime-2 from Prime-3.  The rating agency’s revisions reflected its expectations that our outstanding debt balance and overall capital structure should improve over the next year due largely to higher expected cash flows associated with both completed construction on the Rockies Express, Midcontinent Express, Fayetteville Express and Kinder Morgan Louisiana natural gas pipeline systems, and the businesses and investments we acquired during 2010.  For additional information about our 2010 capital expenditures, acquisition expenditures, and investment contributions, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our 2010 Form 10-K.

 

 

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As a result of this upward revision to our short-term credit rating, we currently have broader access to the commercial paper market that was not available prior to this rating change, and therefore, we expect that our short-term liquidity needs will be met primarily through borrowings under our commercial paper program.  Nevertheless, our ability to satisfy our financing requirements or fund our planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the energy and terminals industries and other financial and business factors, some of which are beyond our control.

 

Additionally, some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.  These financial problems may arise from current global economic conditions, changes in commodity prices or otherwise.  We have been and are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these customers.  We cannot provide assurance that one or more of our current or future financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows; however, we believe we have provided adequate allowance for such customers.

 

Short-term Liquidity

 

Our principal sources of short-term liquidity are (i) our $2.0 billion senior unsecured revolving bank credit facility that matures June 23, 2013; (ii) our $2.0 billion short-term commercial paper program (which is supported by our bank credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings); and (iii) cash from operations.  The loan commitments under our bank credit facility can be used to fund borrowings for general partnership purposes and as a backup for our $2.0 billion commercial paper program.  The facility can be amended to allow for borrowings of up to $2.3 billion.

 

As discussed above in “—General,” we provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our bank credit facility.  After reduction for (i) our letters of credit and (ii) borrowings under our commercial paper program, the remaining available borrowing capacity under our credit facility was $1,420.2 million as of March 31, 2011.

 

Additionally, we have consistently generated strong cash flow from operations.  In the first quarters of 2011 and 2010, we generated $517.5 million and $514.8 million, respectively, of cash from operating activities (the period-to-period increase is discussed below in “—Operating Activities”).

 

Our outstanding short-term debt as of March 31, 2011 was $1,333.2 million, primarily consisting of (i) $500.0 million in principal amount of 9.00% senior notes that mature February 1, 2019, but that we may be required to repurchase at the option of the holder beginning on February 1, 2012 pursuant to certain repurchase provisions contained in the bond indenture; (ii) $450.0 million in principal amount of 7.125% senior notes that mature March 15, 2012; and (iii) $343.0 million of commercial paper borrowings.  We intend to refinance our current short-term debt through a combination of long-term debt, equity, and/or the issuance of additional commercial paper or additional bank credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt.

 

We had working capital deficits (current assets minus current liabilities) of $1,588.5 million as of March 31, 2011 and $1,477.5 million as of December 31, 2010.  The unfavorable change from year-end 2010 was primarily due to a $98.4 million decrease in the net asset value of derivative contracts used to hedge energy commodity cash flows.  Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”).  As a result, our working capital balance could return to a surplus in future periods.  A working capital deficit is not unusual for us or for other companies similar in size and scope to us, and we believe that our working capital deficit does not indicate a lack of liquidity as we continue to maintain adequate current assets and committed lines of credit to satisfy current liabilities and maturing obligations when they come due.  

 

 

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Long-term Financing

 

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

 

Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares).  As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market.  We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. For more information on our first quarter 2011 equity issuances, see Note 5 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.

 

From time to time we issue long-term debt securities, often referred to as our senior notes.  Our senior notes issued to date, other than those issued by our subsidiaries and operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums.  All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries.  Our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.  For more information on our debt related transactions in the first quarter of 2011, including our issuances of senior notes, see Note 4 “Debt” to our consolidated financial statements included elsewhere in this report.

 

As of March 31, 2011 and December 31, 2010, the net carrying value of the various series of our senior notes was $11,276.3 million and $10,876.7 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $129.5 million and $141.0 million, respectively.  To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness.  Based on our historical record, we believe that our capital structure will continue to allow us to achieve our business objectives.  For additional information regarding our debt securities, see Note 8 “Debt” to our consolidated financial statements included in our 2010 Form 10-K/A.

 

We are subject, however, to conditions in the equity and debt markets for our limited partner units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our limited partner units and/or long-term senior notes in the future.  If we were unable or unwilling to issue additional limited partner units, we would be required to either restrict expansion capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings.  Furthermore, our ability to access the public and private debt markets is affected by our credit ratings.  See “—Credit Ratings and Capital Market Liquidity” above for a discussion of our credit ratings.

 

Capital Structure

 

We attempt to maintain a relatively conservative overall capital structure, financing our expansion capital expenditures and acquisitions with approximately 50% equity and 50% debt.  In the short-term, we fund these expenditures from borrowings under our credit facility until the amount borrowed is of a sufficient size to cost effectively offer either debt, or equity, or both.

 

With respect to our debt, we target a debt mixture of approximately 50% fixed and 50% variable interest rates.  We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate payments.

 

Capital Expenditures

 

We define sustaining capital expenditures as capital expenditures which do not increase the capacity of an asset, and for the first quarter of 2011, our sustaining capital expenditures were $35.9 million.  This amount included $0.6 million for our proportionate share of the sustaining capital expenditures of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) KinderHawk Field Services LLC; (iv) Cypress Interstate Pipeline LLC; and (v) Fayetteville Express Pipeline LLC.  For the first quarter of 2010, our sustaining capital expenditures totaled $32.7 million (including less than $0.1 million for our proportionate share of the sustaining capital expenditures of the five equity investees listed above).  Our forecasted expenditures for the remaining nine months of 2011 for sustaining capital expenditures are approximately $187.0 million, including approximately $6.7 million for our proportionate shares of Rockies Express, Midcontinent Express, KinderHawk, Cypress, and Fayetteville Express.

 

 

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Generally, we fund our sustaining capital expenditures with existing cash or from cash flows from operations.  In addition to utilizing cash generated from their own operations, both Rockies Express and Midcontinent Express can each fund their own cash requirements for expansion capital expenditures through borrowings under their own credit facilities, issuing their own long-term notes, or with proceeds from contributions received from their member owners.  Similarly, KinderHawk Field Services and Fayetteville Express can each fund their own cash requirements for expansion capital expenditures with cash generated from their own operations, through borrowings under their own credit facilities, or with proceeds from contributions received from their two member owners.  We have no contingent debt obligations with respect to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, or KinderHawk Field Services LLC; however, we guarantee 50% of Fayetteville Express Pipeline LLC’s bank credit facility borrowings.  For information on our contingent debt obligations, see Note 4 “Debt—Contingent Debt” to our consolidated financial statements included elsewhere in this report.

 

All of our capital expenditures, with the exception of sustaining capital expenditures, are classified as discretionary.  Our discretionary capital expenditures for each of the quarter periods ended March 31, 2011 and 2010 were $229.7 million and $186.1 million, respectively.  The increase in discretionary expenditures from first quarter 2010 was primarily due to higher investment undertaken in the first quarter of 2011 to expand and improve our CO 2 and Terminals business segments.  Generally, we initially fund our discretionary capital expenditures through borrowings under our bank credit facility or our commercial paper program until the amount borrowed is of a sufficient size to cost effectively offer either debt, or equity, or both.  As of March 31, 2011, our current forecast for discretionary capital expenditures for 2011 is approximately $865.0 million.  This amount does not include forecasted capital contributions to our equity investees or forecasted expenditures for asset acquisitions.

 

Operating Activities

 

Net cash provided by operating activities was $517.5 million for the three months ended March 31, 2011, versus $514.8 million in the same comparable period of 2010.  The quarter-to-quarter increase of $2.7 million (1%) in cash flow from operations primarily consisted of:

 

▪

a $23.1 million increase in cash relative to net changes in working capital items, primarily due to (i) a $28.6 million increase in cash from the collection and payment of trade and related party receivables and payables (including collections and payments on natural gas transportation and exchange imbalance receivables and payables), due primarily to the timing of invoices received from customers and paid to vendors and suppliers; (ii) a $27.4 million increase in cash from net changes in accrued tax liabilities, driven by lower net settlements of property tax liabilities in the first quarter of 2011; and (iii) a $37.6 million decrease in cash due to higher interest payments (net of interest collections) in the first quarter of 2011, primarily due to higher average borrowings relative to the first quarter a year ago;

 

▪

a $20.4 million increase in cash from overall higher partnership income—after adjusting our quarter-to-quarter $113.5 million increase in net income for the following four non-cash items: (i) a $158.0 million expense in the first quarter of 2010 resulting from rate case liability adjustments; (ii) an $18.2 million decrease due to higher undistributed earnings from equity investees; (iii) a $5.4 million decrease due to lower non-cash depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments); and (iv) an $88.5 million increase due to certain higher non-cash compensation expenses allocated to us from KMI (as discussed in Note 9 “Related Party Transactions” to our consolidated financial statements included elsewhere in this report, we do not have any obligation, nor do we expect to pay any amounts related to these allocated expenses).  The quarter-to-quarter increase in partnership income in 2011 versus 2010 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes);

 

▪

a $15.0 million increase in cash from higher distributions of earnings from equity investees (distributions of capital are discussed below in “—Investing Activities”).  The increase was chiefly due to incremental distributions of $9.5 million received from our 50%-owned KinderHawk Field Services LLC (acquired in May 2010), and $4.0 million received from our 49%-owned Greens Bayou Fleeting, LLC (formed in February 2011); and

 

 

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▪

a $63.0 million decrease in cash attributable to payments made in March 2011 for transportation rate settlements on our Pacific operations’ refined products pipelines.

 

Investing Activities

 

Net cash used in investing activities was $229.9 million for the three month period ended March 31, 2011, compared to $494.1 million in the comparable 2010 period.  The $264.2 million (53%) increase in cash in the first quarter of 2011 due to lower cash expended for investing activities was primarily attributable to:

 

▪

a $160.4 million increase in cash due to lower acquisitions of assets and investments in the first quarter of 2011.  The increase was driven by the $50.0 million we paid in January 2011 for our preferred equity interest in Watco Companies, LLC (discussed further in Note 2 to our consolidated financial statements included elsewhere in this report), versus the $115.7 million in cash we paid to acquire three unit train ethanol handling terminals from US Development Group LLC in January 2010, and the $97.0 million we paid to acquire certain terminal assets from Slay Industries in March 2010;

 

▪

a $113.4 million increase in cash used due to lower contributions to equity investees in the first quarter of 2011.  In the first quarter of 2011, our capital contributions totaled $22.2 million.  Our contributions included payments of $14.4 million to our 50%-owned Eagle Ford Gathering LLC.  The joint venture used the contributions as partial funding for natural gas gathering infrastructure expansions.  In the first quarter of 2010, we contributed an aggregate amount of $135.6 million, including $130.5 million to Rockies Express Pipeline LLC;

 

▪

a $27.3 million increase in cash due to lower period-to-period payments for margin and restricted deposits associated with energy commodity cash flow hedging activities in the first three months of 2011;

 

▪

a $21.8 million increase in cash due to higher capital distributions (distributions in excess of cumulative earnings) received in the first quarter of 2011, including incremental distributions of $7.0 million received from KinderHawk Field Services LLC, and incremental distributions of $4.2 million received from our 50%-owned Fayetteville Express Pipeline LLC (which began firm contract natural gas transportation to customers on January 1, 2011).  Current accounting practice requires us to classify and report cumulative cash distributions in excess of cumulative equity earnings as a return of capital; however, this change in classification does not impact our cash available for distribution; and

 

▪

a $46.2 million decrease in cash due to higher capital expenditures, as described above in “—Capital Expenditures.”

 

Financing Activities

 

Net cash used in financing activities amounted to $240.8 million for the first three months of 2011.  For the same comparable period last year, we used $29.5 million of net cash for financing activities.  The $211.3 million (716%) overall decrease in cash was mainly due to:

 

▪

a $221.8 million decrease in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs.  The overall decrease in cash was primarily due to (i) a $375.0 million decrease from lower net borrowings under our bank credit facility (due in part to our short-term credit rating upgrade in February 2011, we made no short-term borrowings under our bank credit facility in the first quarter of 2011 but instead made borrowings under our commercial paper program); (ii) a $244.1 million decrease due to higher net commercial paper repayments; and (iii) a combined $392.7 million increase in cash from both issuing and repaying our senior notes (discussed in Note 4 “Debt—Kinder Morgan Energy Partners, L.P. Senior Notes” to our consolidated financial statements included elsewhere in this report);

 

▪

a $63.4 million decrease in cash due to higher partnership distributions in the first quarter of 2011, when compared to the first quarter a year ago.  Distributions to all partners, consisting of our common and Class B unitholders, our general partner and noncontrolling interests, totaled $538.2 million in the first quarter of 2011 and $474.8 million in the first quarter of 2010.  Further information regarding our distributions is discussed following in “—Partnership Distributions;” and

 

 

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▪

an $81.2 million increase in cash from higher partnership equity issuances.  The increase relates to the proceeds we received, after commissions and underwriting expenses, from the sales of additional common units in the first quarter of 2011 (discussed in Note 5 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report).

 

Partnership Distributions

 

Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter.  Our 2010 Form 10-K/A contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including our noncontrolling interests.

 

On February 14, 2011, we paid a quarterly distribution of $1.13 per unit for the fourth quarter of 2010.  This distribution was 8% greater than the $1.05 distribution per unit we paid in February 2010 for the fourth quarter of 2009.  We paid this distribution in cash to our general partner, our common unitholders, and our sole Class B unitholder.  KMR, our sole i-unitholder, received additional i-units based on the $1.13 cash distribution per common unit.

 

The incentive distribution that we paid on February 14, 2011 to our general partner (for the fourth quarter of 2010) totaled $274.6 million, and the incentive distribution that we paid in February 2010 (for the fourth quarter of 2009) totaled $242.3 million.  The increase in the incentive distribution paid to our general partner in the first quarter of 2011 versus the first quarter of 2010 reflects the increase in amounts distributed per unit as well as an increase in the number of common units and i-units outstanding; however, the increase was lower than it otherwise would have been due to a waived incentive amount equal to $7.0 million, related to common units issued to finance a portion of our acquisition of a 50% interest in KinderHawk Field Services LLC (our general partner has agreed not to take incentive distributions related to this acquisition through year-end 2011).

 

On April 20, 2011, we declared a cash distribution of $1.14 per unit for the first quarter of 2011 (an annualized rate of $4.56 per unit).  This distribution was 7% higher than the $1.07 per unit distribution we made for the first quarter of 2010. Under the terms of our partnership agreement, our declared distribution to unitholders for the first quarter of 2011 (which will be paid in the second quarter of 2011) required an incentive distribution to our general partner in the amount of $287.1 million; however, our general partner agreed to waive an incentive amount equal to $7.1 million related to equity issued to finance our acquisition of our 50% interest in KinderHawk Field Services LLC.  Accordingly, our general partner’s incentive distribution for the distribution we declared for the first quarter of 2011 is $280.0 million.  The distribution to unitholders we paid for the first quarter of 2010 (which was paid in the second quarter of 2010) required an incentive distribution to our general partner in the amount of $249.4 million.

 

In November 2010, we announced that we expected to declare cash distributions of $4.60 per unit for 2011, a 4.5% increase over our cash distributions of $4.40 per unit for 2010.  Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO 2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids, and while we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are natural gas liquids volumes. 

 

Our expected growth in distributions in 2011 assumes an average West Texas Intermediate (WTI) crude oil price of approximately $89 per barrel (with some minor adjustments for timing, quality and location differences) in 2011, and based on the actual prices we have received through the date of this report and the forward price curve for WTI (adjusted for the same factors used in our 2011 budget), we currently expect the average price of WTI crude oil will be over $100 per barrel in 2011.  For 2011, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO 2 segment’s cash flows by approximately $5.0 million (or less than 0.2% of our combined business segments’ anticipated earnings before depreciation, depletion and amortization expenses).  This sensitivity to the average WTI price is very similar to what we experienced in 2010.

 

Off Balance Sheet Arrangements

 

Except as set forth with respect to contingent debt agreements with Midcontinent Express Pipeline LLC under “—Contingent Debt” in Note 4 “Debt” to our consolidated financial statements included elsewhere in this report, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2010 in our 2010 Form 10-K.

 

 

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Recent Accounting Pronouncements

 

Please refer to Note 12 “Recent Accounting Pronouncements” to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

 

Information Regarding Forward-Looking Statements

 

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

 

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

 

▪

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

 

▪

changes in our tariff rates implemented by the Federal Energy Regulatory Commission, California Public Utilities Commission, Canada’s National Energy Board or another regulatory agency;

 

▪

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

 

▪

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

 

▪

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

 

▪

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

 

▪

changes in crude oil and natural gas production from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the U.S. Rocky Mountains, areas of shale gas formation 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 our ability to compete;

 

▪

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

 

▪

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

 

▪

our indebtedness, 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;

 

 

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▪

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

 

▪

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

 

▪

capital and credit markets conditions, 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 our success in discovering, developing and producing oil and gas reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

 

▪

engineering and mechanical or technological difficulties that we 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 we may experience;

 

▪

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

 

▪

the timing and success of our business development efforts; and

 

▪

unfavorable results of litigation and the fruition of contingencies referred to in Note 10 to our consolidated financial statements included elsewhere in this report.

 

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 Part I, Item 1A “Risk Factors” of our 2010 Form 10-K for a more detailed description of these and other factors that may affect the forward-looking statements.  When considering forward-looking statements, one should keep in mind the risk factors described in our 2010 Form 10-K.  The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement.  We disclaim any obligation, other than as required by applicable law, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

 

 

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2010, in Item 7A of our 2010 Form 10-K.  For more information on our risk management activities, see Note 6 “Risk Management” to our consolidated financial statements included elsewhere in this report.

 

 

 

 

 

 

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Item 4.   Controls and Procedures.

 

As of March 31, 2011, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.  There has been no change in our internal control over financial reporting during the quarter ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II.   OTHER INFORMATION

 

 

Item 1.  Legal Proceedings.

 

See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.

 

 

Item 1A.  Risk Factors.

 

There have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 2010 Form 10-K.

 

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

 

None.

 

 

Item 3.  Defaults Upon Senior Securities.

 

None.

 

 

Item 4.  (Removed and Reserved)

 

 

Item 5.  Other Information.

 

None.

 

Item 6.   Exhibits.

 

	4.1 —	Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.500% Senior Notes due March 1, 2016, and the 6.375% Senior Notes due March 1, 2041.
	4.2 —	Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601.  Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
	11 —	Statement re: computation of per share earnings.
	12 —	Statement re: computation of ratio of earnings to fixed charges.
	31.1—	Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2—	Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1—	Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

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	32.2—	Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101 —	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three months ended March 31, 2011 and 2010; (ii) our Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010; (iii) our Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010; and (iv) the notes to our Consolidated Financial Statements.

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SIGNATURE

 

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

 

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

  

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

  

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

  

Date:  April 29, 2011				By:		/s/ Kimberly A. Dang
						Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)

 

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