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 September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Revenues
Natural gas sales		$	938.9			$	965.7			$	2,594.9			$	2,831.3
Services			780.1				758.7				2,317.6				2,248.9
Product sales and other			476.1				335.6				1,294.7				1,070.9
Total Revenues			2,195.1				2,060.0				6,207.2				6,151.1
Operating Costs, Expenses and Other
Gas purchases and other costs of sales			942.5				964.6				2,641.5				2,829.2
Operations and maintenance			411.8				328.3				1,199.9				1,098.7
Depreciation, depletion and amortization			253.4				224.1				704.6				674.6
General and administrative			100.5				93.6				387.1				288.1
Taxes, other than income taxes			38.9				41.9				140.8				128.1
Other expense (income)			(0.9	)			0.2				(14.9	)			(6.4	)
Total Operating Costs, Expenses and Other			1,746.2				1,652.7				5,059.0				5,012.3
Operating Income			448.9				407.3				1,148.2				1,138.8
Other Income (Expense)
Earnings from equity investments			72.6				53.7				213.9				155.6
Amortization of excess cost of equity investments			(1.8	)			(1.4	)			(4.9	)			(4.3	)
Interest expense			(133.4	)			(134.0	)			(395.6	)			(374.9	)
Interest income			6.3				5.0				17.4				17.5
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)			(167.2	)			-				(167.2	)			-
Other, net			3.1				5.4				11.1				9.8
Total Other Income (Expense)			(220.4	)			(71.3	)			(325.3	)			(196.3	)
Income Before Income Taxes			228.5				336.0				822.9				942.5
Income Tax (Expense) Benefit			(12.2	)			(13.6	)			(33.8	)			(27.6	)
Net Income			216.3				322.4				789.1				914.9
Net Income Attributable to Noncontrolling Interests			(1.8	)			(1.6	)			(6.3	)			(7.6	)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.		$	214.5			$	320.8			$	782.8			$	907.3
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.		$	214.5			$	320.8			$	782.8			$	907.3
Less: General Partner’s Interest			(298.2	)			(267.3	)			(871.0	)			(609.0	)
Limited Partners’ Interest in Net Income (Loss)		$	(83.7	)		$	53.5			$	(88.2	)		$	298.3
Limited Partners’ Net Income (Loss) per Unit		$	(0.25	)		$	0.17			$	(0.27	)		$	0.98
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit			331.1				310.7				323.3				304.7
Per Unit Cash Distribution Declared		$	1.16			$	1.11			$	3.45			$	3.27

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

table of content

3

---

 

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Millions)

		September 30, 2011				December 31, 2010
		(Unaudited)
ASSETS
Current assets
Cash and cash equivalents		$	271.0			$	129.1
Restricted deposits			0.7				50.0
Accounts, notes and interest receivable, net			823.6				951.8
Inventories			101.3				92.0
Gas in underground storage			27.2				2.2
Fair value of derivative contracts			135.2				24.0
Other current assets			47.0				37.6
Total current assets			1,406.0				1,286.7
Property, plant and equipment, net			15,344.1				14,603.9
Investments			3,272.5				3,886.0
Notes receivable			164.0				115.0
Goodwill			1,303.3				1,233.6
Other intangibles, net			1,167.5				302.2
Fair value of derivative contracts			703.4				260.7
Deferred charges and other assets			217.5				173.0
Total Assets		$	23,578.3			$	21,861.1
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt		$	1,844.4			$	1,262.4
Cash book overdrafts			40.9				32.5
Accounts payable			624.4				630.9
Accrued interest			96.9				239.6
Accrued taxes			100.6				44.7
Deferred revenues			91.9				96.6
Fair value of derivative contracts			71.9				281.5
Accrued other current liabilities			199.3				176.0
Total current liabilities			3,070.3				2,764.2
Long-term liabilities and deferred credits
Long-term debt
Outstanding			10,662.2				10,277.4
Value of interest rate swaps			1,071.2				604.9
Total Long-term debt			11,733.4				10,882.3
Deferred income taxes			243.0				248.3
Fair value of derivative contracts			21.4				172.2
Other long-term liabilities and deferred credits			785.7				501.6
Total long-term liabilities and deferred credits			12,783.5				11,804.4
Total Liabilities			15,853.8				14,568.6
Commitments and contingencies (Notes 4 and 10)
Partners’ Capital
Common units			4,354.7				4,282.2
Class B units			44.9				63.1
i-units			2,807.1				2,807.5
General partner			257.7				244.3
Accumulated other comprehensive income (loss)			172.6				(186.4	)
Total Kinder Morgan Energy Partners, L.P. partners’ capital			7,637.0				7,210.7
Noncontrolling interests			87.5				81.8
Total Partners’ Capital			7,724.5				7,292.5
Total Liabilities and Partners’ Capital		$	23,578.3			$	21,861.1

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

table of content

4

---

 

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

(Unaudited)

		Nine Months Ended September 30,
		2011				2010
Cash Flows From Operating Activities
Net Income		$	789.1			$	914.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			704.6				674.6
Amortization of excess cost of equity investments			4.9				4.3
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)			167.2				-
Noncash compensation expense allocated from parent (Note 9)			89.9				3.7
Earnings from equity investments			(213.9	)			(155.6	)
Distributions from equity investments			200.9				154.9
Proceeds from termination of interest rate swap agreements			73.0				-
Changes in components of working capital:
Accounts receivable			28.2				105.0
Inventories			9.3				(12.8	)
Other current assets			(1.8	)			12.9
Accounts payable			(9.3	)			(26.8	)
Accrued interest			(142.8	)			(125.6	)
Accrued taxes			47.4				32.7
Accrued liabilities			(2.4	)			2.8
Rate reparations, refunds and other litigation reserve adjustments			160.4				(48.3	)
Other, net			70.4				(9.4	)
Net Cash Provided by Operating Activities			1,975.1				1,527.3
Cash Flows From Investing Activities
Acquisitions of investments			(901.0	)			(929.7	)
Acquisitions of assets			(44.0	)			(243.1	)
Capital expenditures			(837.7	)			(722.1	)
Sale or casualty of property, plant and equipment, and other net assets net of removal costs			29.0				21.5
Net proceeds from margin and restricted deposits			55.7				21.7
Contributions to equity investments			(297.0	)			(209.8	)
Distributions from equity investments in excess of cumulative earnings			165.3				153.2
Other, net			3.0				-
Net Cash Used in Investing Activities			(1,826.7	)			(1,908.3	)
Cash Flows From Financing Activities
Issuance of debt			6,356.4				5,704.2
Payment of debt			(5,538.1	)			(4,601.0	)
Repayments from related party			29.3				1.3
Debt issue costs			(17.6	)			(22.5	)
Increase (Decrease) in cash book overdrafts			8.4				(4.4	)
Proceeds from issuance of common units			813.3				636.6
Contributions from noncontrolling interests			15.4				10.2
Distributions to partners and noncontrolling interests:
Common units			(762.1	)			(674.2	)
Class B units			(18.2	)			(17.1	)
General Partner			(858.5	)			(591.4	)
Noncontrolling interests			(20.5	)			(16.7	)
Other, net			0.5				-
Net Cash Provided by Financing Activities			8.3				425.0
Effect of Exchange Rate Changes on Cash and Cash Equivalents			(14.8	)			1.0
Net increase in Cash and Cash Equivalents			141.9				45.0
Cash and Cash Equivalents, beginning of period			129.1				146.6
Cash and Cash Equivalents, end of period		$	271.0			$	191.6

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

table of content

5

---

 

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS   (continued)

(In Millions)

(Unaudited)

		Nine Months Ended September 30,
		2011				2010
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities		$	179.5			$	12.5
Assets acquired by the issuance of common units		$	23.7			$	81.7
Contribution of net assets to investments		$	7.9			$	-
Sale of investment ownership interest in exchange for note		$	4.1			$	-
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)		$	510.2			$	456.6
Cash paid during the period for income taxes		$	9.4			$	(2.8	)

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

table of content

6

---

 

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 such products as ethanol, coal, petroleum coke and steel.  We are also the leading provider of carbon dioxide, commonly called CO 2 , for enhanced oil recovery projects in North America.  Our general partner is owned by Kinder Morgan, Inc., as discussed below.

 

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 September 30, 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 12.4% 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.”

 

Subsequent Event

 

On October 16, 2011, KMI and El Paso Corporation announced a definitive agreement whereby KMI will acquire all of the outstanding shares of El Paso in a transaction that will create an energy company having an enterprise value of approximately $94 billion and 80,000 miles of pipelines.  The total purchase price, including the assumption of debt outstanding at both El Paso Corporation and El Paso Pipeline Partners, L.P., is approximately $38 billion.  El Paso Corporation owns a 42% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P.  The transaction is expected to close in the second quarter of 2012 and is subject to customary regulatory approvals.

 

 

table of content

7

---

 

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 include 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.”

 

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(Loss) per Unit

 

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

 

table of content

8

---

 

2.  Acquisitions 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 consolidated balance sheet.  As of September 30, 2011, our net equity investment in Watco totaled $51.6 million and is included within “Investments” on our accompanying consolidated balance sheet.  We account for our investment under the equity method of accounting, and we include it in our Terminals business segment.

 

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.

 

Deeprock North, LLC

 

On February 17, 2011, Deeprock Energy Resources, LLC, Mecuria Energy Trading, Inc., and our subsidiary Kinder Morgan Cushing LLC, 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 placed in service during the fourth 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 September 30, 2011, our net equity investment in Deeprock North, LLC totaled $22.3 million and is included within “Investments” on our accompanying consolidated balance sheet.

 

TGS Development, L.P. Terminal Acquisition  

 

On June 10, 2011, we acquired a newly constructed petroleum coke terminal located in Port Arthur, Texas from TGS Development, L.P. (TGSD) for an aggregate consideration of $74.1 million, consisting of $42.9 million in cash, $23.7 million in common units, and an obligation to pay additional consideration of $7.5 million.  We estimate our remaining $7.5 million obligation will be paid to TGSD approximately one year from the closing (in May or June 2012), and will be settled in a combination of cash and common units, depending on TGSD’s election.

 

All of the acquired assets are located in Port Arthur, Texas, and include long-term contracts to provide petroleum coke handling and cutting services to improve the refining of heavy crude oil at Total Petrochemicals USA Inc.’s recently expanded Port Arthur refinery.  The refinery is expected to produce more than one million tons of petroleum coke annually.  Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired, we assigned $42.6 million of our combined purchase price to “Property, plant and equipment, net,” and the remaining $31.5 million to “Other intangibles, net,” representing the combined fair values of two separate intangible customer contracts with Total.  The acquisition complements our existing Gulf Coast bulk terminal facilities and expands our pre-existing petroleum coke handling operations.  All of the acquired assets are included as part of our Terminals business segment.

 

table of content

9

---

 

KinderHawk Field Services LLC and EagleHawk Field Services LLC

 

Effective July 1, 2011, we acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC that we did not already own and a 25% equity ownership interest in Petrohawk’s natural gas gathering and treating business located in the Eagle Ford shale formation in South Texas for an aggregate consideration of $912.1 million, consisting of $835.1 million in cash and assumed debt of $77.0 million (representing 50% of KinderHawk’s borrowings under its bank credit facility as of July 1, 2011).  We then repaid the outstanding $154.0 million of borrowings and following this repayment, KinderHawk had no outstanding debt.

 

Following our acquisition of the remaining ownership interest on July 1, 2011, we changed our method of accounting from the equity method to full consolidation, and due to the fact that we acquired a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value.  We recognized a $167.2 million non-cash loss as a result of this remeasurement.  The loss amount represents the excess of the carrying value of our investment ($910.2 million as of July 1, 2011) over its fair value ($743.0 million), and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011.

 

We then measured the fair values of the acquired identifiable tangible and intangible assets and the assumed liabilities on the acquisition date, and assigned the following amounts:

 

▪

$35.5 million to current assets, primarily consisting of trade receivables and materials and supplies inventory;

 

▪

$641.6 million to property, plant and equipment;

 

▪

$93.4 million to our 25% investment in EagleHawk;

 

▪

$883.2 million to a long-term intangible customer contract, representing the contract value of natural gas gathering services to be performed for Petrohawk over an approximate 20-year period; less

▪

$92.8 million assigned to assumed liabilities, not including $77.0 million for the 50% of KinderHawk’s borrowings under its bank credit facility that we were previously responsible for.

 

Based on the excess of (i) the consideration we transferred ($912.1 million) and the fair value of our previously held interest ($743.0 million); over (ii) the combined fair value of net assets acquired ($1,560.9 million), we recognized $94.2 million of “Goodwill.”  This goodwill intangible asset represents the future economic benefits expected to be derived from this strategic acquisition that are not assignable to other individually identifiable, separately recognizable assets acquired.  We believe the primary items that generated the goodwill are the value of the synergies created by expanding our natural gas gathering operations, and furthermore, we expect this entire amount of goodwill to be deductible for tax purposes.

 

KinderHawk Field Services LLC owns and operates the largest natural gas gathering and midstream business in the Haynesville shale formation located in northwest Louisiana, consisting of more than 400 miles of pipeline with over 2.0 billion cubic feet per day of pipeline capacity.  Currently, it gathers approximately 1.0 billion cubic feet of natural gas per day.  We operate KinderHawk Field Services LLC, and we acquired our original 50% ownership interest in KinderHawk Field Services LLC from Petrohawk on May 21, 2010.

 

The Eagle Ford natural gas gathering joint venture is named EagleHawk Field Services LLC, and we account for our 25% investment under the equity method of accounting.  Petrohawk operates EagleHawk Field Services LLC and owns the remaining 75% ownership interest.  The joint venture owns two midstream gathering systems in and around Petrohawk’s Hawkville and Black Hawk areas of Eagle Ford and combined, the joint venture’s assets will consist of more than 280 miles of gas gathering pipelines and approximately 140 miles of condensate lines to be in service by the end of 2011.  It also has a life of lease dedication of Petrohawk’s Eagle Ford reserves that provides Petrohawk and other Eagle Ford producers with gas and condensate gathering, treating and condensate stabilization services.

 

The acquisition of the remaining ownership interest in KinderHawk and the equity ownership interest in EagleHawk complemented and expanded our existing natural gas gathering operations, and all of the acquired assets are included in our Natural Gas Pipelines business segment.  Additionally, on August 25, 2011, mining and oil company BHP Billiton completed its previously announced acquisition of Petrohawk Energy Corporation through a short-form merger under Delaware law.  The merger was closed with Petrohawk being the surviving corporation as a wholly owned subsidiary of BHP Billiton.  The acquisition will not affect the terms of our contracts with Petrohawk.

 

table of content

10

---

 

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.

 

Divestitures

 

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 Tax (Expense) Benefit” in our accompanying consolidated statement of income for the nine months ended September 30, 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.

 

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, for an aggregate consideration of $8.1 million, consisting of a $4.1 million note receivable, $1.0 million in cash, and a $3.0 million receivable for the settlement of working capital items.  Following the sale, we continue to own 49% membership interests in both River Consulting, LLC, a company engaged in the business of providing engineering, consulting and management services, and Devco USA, L.L.C., a company engaged in the business of processing, handling and marketing sulfur, and selling related pouring equipment.  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 $8.8 million and consisted mostly of technology-based assets and trade receivables.  We now account for our retained investments under the equity method of accounting.

 

In the second quarter of 2011, we recognized a $3.6 million pre-tax gain from the sale of these ownership interests (including a $2.1 million gain related to the remeasurement of our retained investment to fair value) and we included this gain within the caption “Other, net” in our accompanying consolidated statements of income for the nine months ended September 30, 2011.  We also recognized a $1.4 million increase in income tax expense related to this gain, which is included within the caption “Income Tax (Expense) Benefit” in our accompanying consolidated statement of income for the nine months ended September 30, 2011.

 

Arrow Terminals B.V.                

 

Effective August 31, 2011, we sold the outstanding share capital of our wholly-owned subsidiary Arrow Terminals B.V. to Pacorini Metals Europe B.V. for an aggregate consideration of $13.3 million in cash.  Arrow Terminals B.V. owns and operates a bulk terminal facility located in the seaport area of Vlissingen, Netherlands.  The terminal is primarily engaged in the business of storing, handling and distributing bulk ferro alloys and general commodities.  Including the removal of our cumulative translation adjustments balance and our estimated costs to sell, we recognized a $1.3 million pre-tax gain from the sale of Arrow Terminals B.V. and we included this gain within the caption “Other expense (income)” in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011.

 

table of content

11

---

 

Acquisition Subsequent to September 30, 2011

 

On October 24, 2011, we announced that we have signed a definitive purchase and sale agreement to acquire the natural gas treating assets of SouthTex Treaters for approximately $155.0 million in cash.  SouthTex Treaters is a leading manufacturer, designer and fabricator of natural gas treating plants that are used to remove impurities (carbon dioxide and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications.  The acquisition complements and expands our existing natural gas treating business, and all of the acquired operations will be included in our Natural Gas Pipelines business segment.  The transaction is expected to close in the fourth quarter of 2011, and we will then also assign our total purchase price to assets acquired and liabilities assumed.

 

 

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, but combined with Products Pipelines for presentation in the table below); (iii) Natural Gas Pipelines; (iv) CO 2 ; (v) Terminals; and (vi) Kinder Morgan Canada.  There were no impairment charges resulting from our May 31, 2011 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 8.0%.  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 nine months ended September 30, 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(b).			-				94.2				-				-				-				94.2
Disposals(c).			-				-				-				(11.8	)			-				(11.8	)
Impairments			-				-				-				-				-				-
Currency translation adjustments			-				-				-				-				(12.7	)			(12.7	)
Balance as of September 30, 2011		$	263.2			$	431.2			$	46.1			$	326.1			$	236.7			$	1,303.3

__________

(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 U.S. 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)	2011 acquisition amount relates to our July 2011 purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own (discussed further in Note 2).
(c)	2011 disposal amount consists of (i) $10.6 million related to the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; and (ii) $1.2 million related to the sale of our subsidiary Arrow Terminals B.V. (both discussed further in Note 2).

 

table of content

12

---

 

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 nine months of 2011.

 

As of September 30, 2011 and December 31, 2010, we reported $138.2 million and $283.0 million, respectively, in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.  The decrease in our equity method goodwill since December 31, 2010 was due to our July 2011 purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own (discussed further in Note 2).  Effective July 1, 2011, we exchanged our status as an owner of an equity investment in KinderHawk for a full controlling financial interest, and we began accounting for our investment under the full consolidation method.

 

Other Intangibles

 

Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, lease value, and technology-based assets.  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):

 

		September 30, 2011				December 31, 2010
Customer relationships, contracts and agreements
Gross carrying amount		$	1,312.7			$	399.8
Accumulated amortization			(152.0	)			(112.0	)
Net carrying amount			1,160.7				287.8
Lease value, technology-based assets and other
Gross carrying amount			10.6				17.9
Accumulated amortization			(3.8	)			(3.5	)
Net carrying amount			6.8				14.4
Total Other intangibles, net		$	1,167.5			$	302.2

 

The increase in the carrying amount of our customer relationships, contacts and agreements since December 31, 2010 was mainly due to the acquisition of (i) a natural gas gathering customer contract in July 2011, associated with our purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own; and (ii) two separate petroleum coke handling customer contracts in June 2011, associated with our purchase of terminal assets from TGS Development, L.P.  Both acquisitions are described further in Note 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 and nine months ended September 30, 2011, the amortization expense on our intangibles totaled $20.9 million and $40.3 million, respectively, and for the same prior year periods, the amortization expense on our intangibles totaled $11.5 million and $33.9 million, respectively. As of September 30, 2011, the weighted average amortization period for our intangible assets was approximately 18.6 years, and our estimated amortization expense for these assets for each of the next five fiscal years (2012 – 2016) is approximately $77.1 million, $73.2 million, $70.1 million, $67.3 million and $63.8 million, respectively.

 

 

 

table of content

13

---

 

 

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 September 30, 2011 and December 31, 2010 was $12,506.6 million and $11,539.8 million, respectively.  The weighted average interest rate on all of our borrowings (both short-term and long-term) was approximately 4.12% during the third quarter of 2011, and approximately 4.42% during the third quarter of 2010.  For the first nine months of 2011 and 2010, the weighted average interest rate on all of our borrowings was approximately 4.28% and 4.34%, respectively.

 

Our outstanding short-term debt as of September 30, 2011 was $1,844.4 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 $449.9 million as of September 30, 2011); (iii) $500.0 million in principal amount of 5.850% senior notes due September 15, 2012 (including discount, the notes had a carrying amount of $499.9 million as of September 30, 2011); (iv) $353.0 million of commercial paper borrowings; (v) $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); (vi) a $9.7 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); (vii) a $7.5 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes); and (viii) a $0.7 million portion of 6.00% long-term note payable (our subsidiary Kinder Morgan Arrow Terminals, L.P. is the obligor on the note).

 

Credit Facility

 

On July 1, 2011, we amended our $2.0 billion three-year, senior unsecured revolving credit facility to, among other things, (i) allow for borrowings of up to $2.2 billion; (ii) extend the maturity of the credit facility from June 23, 2013 to July 1, 2016; (iii) permit an amendment to allow for borrowings of up to $2.5 billion; and (iv) decrease the interest rates and commitment fees for borrowings under this facility.  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 commercial paper program.  There were no borrowings under the credit facility as of September 30, 2011 or as of December 31, 2010.

 

Additionally, as of September 30, 2011, the amount available for borrowing under our credit facility was reduced by   a combined amount of $584.8 million, consisting of $353.0 million of commercial paper borrowings and $231.8 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 $10.7 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $17.0 million in other letters of credit supporting other obligations of us and our subsidiaries.

 

Commercial Paper Program

 

In July 2011, in conjunction with the amendment to our revolving credit facility, we increased our commercial paper program to provide for the issuance of up to $2.2 billion of commercial paper (up from $2.0 billion).  Our unsecured revolving credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

 

As of September 30, 2011, we had $353.0 million of commercial paper outstanding with an average interest rate of 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, and 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.

 

table of content

14

---

 

 

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 deducting the underwriting discount, of $1,092.7 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

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.

 

In addition, on August 17, 2011, we completed a public offering of $750 million in principal amount of senior notes in two separate series, consisting of $375 million of 4.150% notes due March 1, 2022, and $375 million of 5.625% notes due September 1, 2041.  We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $743.3 million, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

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 September 30, 2011, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $9.7 million.  As of December 31, 2010, the net present value of the note was $19.2 million.

 

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 nine months of 2011, we paid a combined principal amount of $5.4 million, and as of September 30, 2011, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $18.2 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.

 

Kinder Morgan Arrow Terminals, L.P. Debt

 

On April 4, 2011, our subsidiary Kinder Morgan Arrow Terminals, L.P. acquired a parcel of land and a terminal warehouse located in Industry, Pennsylvania from a third party for an aggregate consideration of $3.3 million, consisting of $1.2 million in cash and a $2.1 million promissory note payable.  The note principal is payable in three annual payments beginning in March 2012.  The note bears interest at 6% per annum, and accrued interest on the unpaid principal amount is due and payable on the due date of each principal installment.

 

KinderHawk Field Services LLC Credit Facility

 

On July 1, 2011, immediately following our acquisition of KinderHawk Field Services LLC (discussed in Note 2), we repaid the outstanding $154.0 million of borrowings under KinderHawk’s revolving bank credit facility and following this repayment, KinderHawk had no outstanding debt.  The revolving bank credit facility was terminated at the time of such repayment.

 

table of content

15

---

 

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.  As of September 30, 2011, our contingent debt obligations, as well as our obligations with respect to related letters of credit, consisted of the following two items:

 

▪

an aggregate $80.7 million for our contingent share (50%) of Cortez Pipeline Company’s debt obligations, consisting of (i) $70.0 million for our contingent share of outstanding borrowings under Cortez’s debt facilities (described below); and (ii) $10.7 million for a letter of credit issued on our behalf to secure our indemnification obligations to Shell for 50% of the $21.4 million in principal amount of Cortez’s Series D notes outstanding as of that date.  Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system.

 

We are severally liable for our percentage ownership share (50%) of Cortez’s debt, and as of September 30, 2011, Cortez’s debt facilities consisted of (i) $21.4 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) $18.5 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.  Accordingly, as of September 30, 2011, our contingent share of Cortez’s debt was $70.0 million (50% of total borrowings).

 

With respect to the Series D notes, Shell Oil Company shares our several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of September 30, 2011, we have a letter of credit in the amount of $10.7 million issued by JPMorgan Chase Bank, in order to secure our indemnification obligations to Shell for 50% of the $21.4 million in principal amount of Series D notes outstanding as of that date.

 

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; and

 

▪

an $18.3 million letter of credit posted 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 September 30, 2011, this letter of credit had a face amount of $18.3 million.

 

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.

 

On July 28, 2011, Fayetteville Express Pipeline LLC entered into (i) a new unsecured $600.0 million term loan that is due on July 28, 2012, with the ability to extend one additional year; and (ii) a $50.0 million unsecured revolving bank credit facility that is due on July 28, 2015.  These debt instruments replaced Fayetteville Express’ $1.1 billion credit facility that was terminated on July 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 Fayetteville Express Pipeline LLC. 

 

table of content

16

---

 

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 September 30, 2011 and December 31, 2010, our partners’ capital included the following limited partner units:

 

		September 30,				December 31,
		2011				2010
Common units			230,843,095				218,880,103
Class B units			5,313,400				5,313,400
i-units			96,807,608				91,907,987
Total limited partner units			332,964,103				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 right to receive incentive distributions.

 

As of September 30, 2011, our total common units consisted of 214,472,667 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 September 30, 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.

 

As of both September 30, 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.

 

 

 

 

 

 

 

table of content

17

---

 

 

Changes in Partners’ Capital

 

For each of the three and nine month periods ended September 30, 2011 and 2010, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income are summarized as follows (in millions):

 

		Three Months Ended September 30,
		2011												2010
		KMP				Noncontrolling Interests				Total				KMP				Noncontrolling interests				Total
Beginning Balance		$	7,616.2			$	87.7			$	7,703.9			$	7,023.1			$	83.1			$	7,106.2
Units issued for cash			107.5				-				107.5				203.5				-				203.5
Distributions paid in cash			(566.5	)			(7.0	)			(573.5	)			(333.7	)			(4.7	)			(338.4	)
Noncash compensation expense allocated from KMI(a)			-				-				-				1.0				-				1.0
Cash contributions			-				2.3				2.3				-				3.0				3.0
Other adjustments			(4.1	)			-				(4.1	)			(0.2	)			-				(0.2	)
Comprehensive income:
Net Income			214.5				1.8				216.3				320.8				1.6				322.4
Other comprehensive income:
Change in fair value of derivatives utilized for hedging purposes			382.7				3.9				386.6				(82.5	)			(0.8	)			(83.3	)
Reclassification of change in fair value of derivatives to  net income			48.5				0.5				49.0				47.2				0.4				47.6
Foreign currency translation adjustments			(161.8	)			(1.7	)			(163.5	)			62.2				0.7				62.9
Adjustments to pension and other postretirement benefit plan liabilities			-				-				-				0.3				-				0.3
Total other comprehensive income			269.4				2.7				272.1				27.2				0.3				27.5
Comprehensive income			483.9				4.5				488.4				348.0				1.9				349.9
Ending Balance		$	7,637.0			$	87.5			$	7,724.5			$	7,241.7			$	83.3			$	7,325.0

__________

table of content

18

---

 

		Nine Months Ended September 30,
		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			23.7				-				23.7				81.7				-				81.7
Units issued for cash			813.3				-				813.3				636.6				-				636.6
Distributions paid in cash			(1,638.8	)			(20.5	)			(1,659.3	)			(1,282.7	)			(16.7	)			(1,299.4	)
Noncash compensation expense allocated from KMI(a)			89.0				0.9				89.9				3.7				-				3.7
Cash contributions			-				15.4				15.4				-				10.2				10.2
Other adjustments			(2.9	)			-				(2.9	)			(0.2	)			-				(0.2	)
Comprehensive income:
Net Income			782.8				6.3				789.1				907.3				7.6				914.9
Other comprehensive income:
Change in fair value of derivatives utilized for hedging purposes			285.9				2.9				288.8				83.5				0.9				84.4
Reclassification of change in fair value of derivatives to  net income			186.9				1.9				188.8				133.3				1.3				134.6
Foreign currency translation adjustments			(100.8	)			(1.0	)			(101.8	)			35.9				0.4				36.3
Adjustments to pension and other postretirement benefit plan liabilities			(13.0	)			(0.2	)			(13.2	)			(2.1	)			-				(2.1	)
Total other comprehensive income			359.0				3.6				362.6				250.6				2.6				253.2
Comprehensive income			1,141.8				9.9				1,151.7				1,157.9				10.2				1,168.1
Ending Balance		$	7,637.0			$	87.5			$	7,724.5			$	7,241.7			$	83.3			$	7,325.0

____________

 

(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 nine 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 and nine months ended September 30, 2011, we issued 1,553,285 and 3,930,581, respectively, of our common units pursuant to this equity distribution agreement.  After commissions of $0.9 million and $2.2 million, respectively, we received net proceeds of $107.5 million and $279.4 million, respectively, 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.

 

On June 10, 2011, we issued 324,961 common units as part of our purchase price for the petroleum coke terminal assets we acquired from TGS Development, L.P.  We valued the common units at $23.7 million, determining the units’ value based on the $73.01 closing market price of the common units on the New York Stock Exchange on the June 10, 2011 acquisition date.  For more information on this acquisition, see Note 2.

 

table of content

19

---

 

 

On June 17, 2011, we issued, in a public offering, 6,700,000 of our common units at a price of $71.44 per unit, less commissions and underwriting expenses.  At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 1,005,000 common units from us on the same terms and conditions, and upon the underwriters’ exercise of this option in full, we issued the additional 1,005,000 common units on June 27, 2011.  We received net proceeds, after deducting the underwriter discount, of $533.9 million from the issuance of these 7,705,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

Equity Issuances Subsequent to September 30, 2011

 

In October 2011, we issued 58,092 of our common units for the settlement of sales made on or before September 30, 2011 pursuant to our equity distribution agreement.  We received net proceeds of $4.0 million for the issuance of these 58,092 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.

 

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 August 12, 2011, we paid a cash distribution of $1.15 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended June 30, 2011.  KMR, our sole i-unitholder, received a distribution of 1,701,916 i-units from us on August 12, 2011, based on the $1.15 per unit distributed to our common unitholders on that date.  The distributions were declared on July 20, 2011, payable to unitholders of record as of August 1, 2011.

 

On August 13, 2010, we paid a cash distribution of $1.09 per unit to our common unitholders and our Class B unitholders for the quarterly period ended June 30, 2010.  KMR, our sole i-unitholder, received a distribution of 1,625,869 i-units from us on August 13, 2010, based on the $1.09 per unit distributed to our common unitholders on that date.  The distributions were declared on July 21, 2010, payable to unitholders of record as of July 30, 2010.

 

Our August 12, 2011 incentive distribution payment to our general partner for the quarterly period ended June 30, 2011 totaled $292.8 million; however, this incentive distribution was affected by a waived incentive distribution amount equal to $7.1 million related to common units issued to finance a portion of our May 2010 acquisition of a 50% ownership interest in KinderHawk Field Services LLC.  B eginning with our distribution payments for the quarterly period ended June 30, 2010 (discussed following), our general partner has agreed not to take incentive distributions related to this joint venture acquisition through year-end 2011.

 

On August 13, 2010, we paid an incentive distribution to our general partner for the second quarter of 2010 totaling $89.8 million.  Based on a limited partner distribution of $1.09 per unit to our common unitholders, our general partner would expect to receive an incentive distribution in the amount of $263.4 million; however, this incentive distribution was reduced by a combined $173.6 million, including (i) a waived incentive amount equal to $5.3 million related to our May 2010 KinderHawk acquisition; and (ii) a reduced incentive amount equal to $168.3 million due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations (including the general partner’s 2% general partner interest, its total cash distributions were reduced by $170.0 million).  

 

Our distribution of cash for the second quarter of 2010 (which we paid in the third quarter of 2010) from interim capital transactions totaled $177.1 million (approximately $0.56 per limited partner unit), and p ursuant to the provisions of our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, this distribution from interim capital transactions helped preserve our cumulative excess cash coverage.  In the first nine months of 2011 and 2010, we made incentive distribution payments to our general partner totaling $847.4 million and $581.5 million, respectively.

 

 

table of content

20

---

 

Subsequent Event

 

On October 19, 2011, we declared a cash distribution of $1.16 per unit for the quarterly period ended September 30, 2011.  The distribution will be paid on November 14, 2011, to unitholders of record as of October 31, 2011.  Our common unitholders and our Class B unitholder will receive cash.  KMR will receive a distribution of 1,701,781 additional i-units based on the $1.16 distribution per common unit.  For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017579) will be issued.  This fraction was determined by dividing:

 

▪     $1.16, the cash amount distributed per common unit

 

by

 

▪

$65.986, the average of KMR’s shares’ closing market prices from October 13-26, 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 third quarter of 2011 of $1.16 per unit will result in an incentive distribution to our general partner of $299.0 million (including the effect of a waived incentive distribution amount of $7.2 million related to our May 2010 KinderHawk acquisition).  Comparatively, our distribution of $1.11 per unit paid on November 12, 2010 for the third quarter of 2010 resulted in an incentive distribution payment to our general partner in the amount of $266.7 million.  The increased incentive distribution to our general partner for the third quarter of 2011 over the incentive distribution for the third quarter of 2010 reflects the increase in the amount distributed per unit as well as the issuance of additional units.  For additional information about our 2010 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included in our 2010 Form 10-K/A.

 

 

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 U.S. generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective (as defined by U.S. 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 U.S. 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 three and nine months ended September 30, 2011, we recognized net gains of $8.5 million and $10.4 million, respectively, related to crude oil hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.  During the three and nine months ended September 30, 2010, we recognized net losses of $9.5 million and net gains of $4.6 million, respectively, related to crude oil and natural gas hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.

 

table of content

21

---

 

Additionally, during the three and nine months ended September 30, 2011, we reclassified losses of $49.0 million and $188.8 million, respectively, from “Accumulated other comprehensive loss” into earnings, and for the same comparable periods last year, we reclassified losses of $47.6 million and $134.6 million, respectively, 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 gain” balance included in our Partners’ Capital (exclusive of the portion included in “Noncontrolling interests”) was $172.6 million as of September 30, 2011.  As of December 31, 2010, we had an “Accumulated other comprehensive loss” balance of $186.4 million.  These totals included a $165.1 million gain amount and a $307.1 million loss amount, respectively, associated with energy commodity price risk management activities.  Approximately $56.7 million of the total gain amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of September 30, 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 September 30, 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.

 

As of September 30, 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	(21.8) million barrels
Natural gas fixed price	(3.6) billion cubic feet
Natural gas basis	(4.2) billion cubic feet
Derivatives not designated as hedging contracts
Natural gas fixed price	0.2 billion cubic feet
Natural gas basis	2.3 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.

 

table of content

22

---

 

As of September 30, 2011, we had a combined notional principal amount of $5,325 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 September 30, 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 March 15, 2035.

 

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 March 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.

 

In August 2011, we entered into two additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $250 million, effectively converting a portion of the interest expense associated with our 4.15% senior notes due March 1, 2022 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.  We also terminated two existing fixed-to-variable swap agreements having a combined notional principal amount of $200 million in two separate transactions.  We received combined proceeds of $73.0 million from the early termination of these swap agreements.

 

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 September 30, 2011 and December 31, 2010 (in millions):

 

Fair Value of Derivative Contracts
			Asset derivatives								Liability derivatives
			September 30,				December 31,				September 30,				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		$	123.7			$	20.1			$	(67.0	)		$	(275.9	)
	Non-current			133.0				43.1				(21.4	)			(103.0	)
Subtotal				256.7				63.2				(88.4	)			(378.9	)
Interest rate swap agreements	Current			6.1				-				-				-
	Non-current			570.4				217.6				-				(69.2	)
Subtotal				576.5				217.6				-				(69.2	)
Total				833.2				280.8				(88.4	)			(448.1	)
Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Current			5.4				3.9				(4.9	)			(5.6	)
Total				5.4				3.9				(4.9	)			(5.6	)
Total derivatives			$	838.6			$	284.7			$	(93.3	)		$	(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 September 30, 2011 and December 31, 2010, this unamortized premium totaled $494.7 million and $456.5 million, respectively, and as of September 30, 2011, the weighted average amortization period for this premium was approximately 17.9 years.

 

table of content

23

---

 

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 and nine months ended September 30, 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)
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2011				2010				2011				2010
Interest rate swap agreements	Interest, net - income/(expense)		$	436.8			$	219.9			$	501.1			$	634.1
Total			$	436.8			$	219.9			$	501.1			$	634.1

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 item(a)
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2011				2010				2011				2010
Fixed rate debt	Interest, net - income/(expense)		$	(436.8	)		$	(219.9	)		$	(501.1	)		$	(634.1	)
Total			$	(436.8	)		$	(219.9	)		$	(501.1	)		$	(634.1	)

____________

 

(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.

____________

 

Derivatives in cash flow hedging relationships

Amount of gain/(loss) recognized in OCI on derivative (effective portion)

Location of gain/(loss) recognized 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 Ended									Three Months Ended									Three Months Ended
	September 30,									September 30,									September 30,
	2011				2010					2011				2010					2011				2010
Energy commodity  derivative contracts		$	386.6			$	(83.3	)	Revenues–natural  gas sales		$	-			$	3.6		Revenues–natural  gas sales		$	-			$	-
									Revenues–product  sales and other			(50.5	)			(44.2	)	Revenues–product  sales and other			8.5				(7.9	)
									Gas purchases and  other costs of sales			1.5				(7.0	)	Gas purchases and  other costs of sales			-				(1.6	)
Total		$	386.6			$	(83.3	)	Total		$	(49.0	)		$	(47.6	)	Total		$	8.5			$	(9.5	)

	Nine Months Ended									Nine Months Ended									Nine Months Ended
	September 30,									September 30,									September 30,
	2011				2010					2011				2010					2011				2010
Energy commodity  derivative contracts		$	288.8			$	84.4		Revenues–natural  gas sales		$	1.0			$	5.3		Revenues–natural  gas sales		$	-			$	-
									Revenues–product  sales and other			(202.7	)			(142.6	)	Revenues–product  sales and other			10.4				5.4
									Gas purchases and  other costs of sales			12.9				2.7		Gas purchases and  other costs of sales			-				(0.8	)
Total		$	288.8			$	84.4		Total		$	(188.8	)		$	(134.6	)	Total		$	10.4			$	4.6

____________

 

 

table of content

24

---

 

 

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								Nine Months Ended
			September 30,								September 30,
			2011				2010				2011				2010
Energy commodity derivative contracts	Gas purchases and other costs of sales		$	(0.1	)		$	0.2			$	0.1			$	1.0
Total			$	(0.1	)		$	0.2			$	0.1			$	1.0

____________

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 September 30, 2011 was (in millions):

 

		Asset position
Interest rate swap agreements		$	576.5
Energy commodity derivative contracts			262.1
Gross exposure			838.6
Netting agreement impact			(78.5	)
Net exposure		$	760.1

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 September 30, 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 September 30, 2011 and December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $8.9 million and $2.4 million, respectively, and we reported these amounts within “Accrued other current liabilities” in our accompanying consolidated balance sheets.  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 September 30, 2011, we estimate that if our credit rating was downgraded, we would have the following additional collateral obligations (in millions):

 

table of content

25

---

 

 

Credit ratings downgraded (a)		Incremental obligations				Cumulative obligations(b)
One notch to BBB-/Baa3		$	-			$	-
Two notches to below BBB-/Baa3 (below investment grade)		$	12.8			$	12.8

_________

(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 $12.8 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).

 

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 September 30, 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.

 

 

 

 

 

 

table of content

26

---

 

 

		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 September 30, 2011
Energy commodity derivative contracts(a)		$	262.1			$	25.3			$	172.2			$	64.6
Interest rate swap agreements		$	576.5			$	-			$	576.5			$	-
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 September 30, 2011
Energy commodity derivative contracts(a)		$	(93.3	)		$	(12.6	)		$	(60.7	)		$	(20.0	)
Interest rate swap agreements		$	-			$	-			$	-			$	-
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.

 

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 and nine months ended September 30, 2011 and 2010 (in millions):

 

Significant unobservable inputs (Level 3)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Derivatives-net asset (liability)
Beginning of Period		$	6.7			$	46.6			$	18.8			$	13.0
Transfers into Level 3			-				-				-				-
Transfers out of Level 3			-				-				-				-
Total gains or (losses):
Included in earnings			2.6				(7.5	)			5.4				3.6
Included in other comprehensive income			37.0				(3.9	)			21.5				11.7
Purchases			-				-				4.6				-
Issuances			-				-				-				-
Sales			-				-				-				-
Settlements			(1.7	)			(0.6	)			(5.7	)			6.3
End of Period		$	44.6			$	34.6			$	44.6			$	34.6
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		$	3.2			$	(5.8	)		$	4.4			$	1.3

table of content

27

---

 

 

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 September 30, 2011 and December 31, 2010 (both short-term and long-term, but excluding the value of interest rate swaps) is disclosed below (in millions):

 

		September 30, 2011								December 31, 2010
		Carrying Value				Estimated Fair value				Carrying Value				Estimated fair value
Total debt		$	12,506.6			$	13,873.0			$	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

 

▪

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 segment’s 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.

 

 

 

 

 

 

 

table of content

28

---

 

 

Financial information by segment follows (in millions):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Revenues
Products Pipelines
Revenues from external customers		$	241.6			$	227.7			$	694.6			$	661.5
Natural Gas Pipelines
Revenues from external customers			1,176.4				1,147.6				3,240.1				3,414.0
CO 2
Revenues from external customers			372.0				296.0				1,062.8				932.4
Terminals
Revenues from external customers			327.7				321.2				979.4				945.3
Intersegment revenues			0.4				0.3				0.9				0.8
Kinder Morgan Canada
Revenues from external customers			77.4				67.5				230.3				197.9
Total segment revenues			2,195.5				2,060.3				6,208.1				6,151.9
Less: Total intersegment revenues			(0.4	)			(0.3	)			(0.9	)			(0.8	)
Total consolidated revenues		$	2,195.1			$	2,060.0			$	6,207.2			$	6,151.1

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Segment earnings before depreciation, depletion, amortization And amortization of excess cost of equity investments(a)
Products Pipelines(b)		$	102.7			$	167.5			$	303.9			$	339.1
Natural Gas Pipelines(c)			80.8				187.3				484.7				592.9
CO 2			294.8				221.5				823.2				724.1
Terminals			179.8				159.2				524.5				475.2
Kinder Morgan Canada			48.5				44.0				150.0				132.9
Total segment earnings before DD&A			706.6				779.5				2,286.3				2,264.2
Total segment depreciation, depletion and amortization			(253.4	)			(224.1	)			(704.6	)			(674.6	)
Total segment amortization of excess cost of investments			(1.8	)			(1.4	)			(4.9	)			(4.3	)
General and administrative expenses(d)			(100.5	)			(93.6	)			(387.1	)			(288.1	)
Interest expense, net of unallocable interest income			(132.5	)			(133.8	)			(393.8	)			(373.9	)
Unallocable income tax expense			(2.1	)			(4.2	)			(6.8	)			(8.4	)
Total consolidated net income		$	216.3			$	322.4			$	789.1			$	914.9

 

		September 30, 2011				December 31, 2010
Assets
Products Pipelines		$	4,398.3			$	4,369.1
Natural Gas Pipelines			9,711.8				8,809.7
CO 2			2,322.1				2,141.2
Terminals			4,376.6				4,138.6
Kinder Morgan Canada			1,804.1				1,870.0
Total segment assets			22,612.9				21,328.6
Corporate assets(e)			965.4				532.5
Total consolidated assets		$	23,578.3			$	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)	Three and nine month 2011 amounts include increases in expense of $69.3 million and $234.3 million, respectively, primarily associated with adjustments to rate case reserves and rights-of-way lease payment obligations.  Nine month 2010 amount includes a $158.0 million increase in expense associated with rate case liability adjustments.
(c)	Three and nine month 2011 amounts include a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value (discussed further in Note 2).
(d)	Nine month 2011 amount includes an $87.1 million increase in expense associated with a one-time special cash bonus payment 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.
(e)	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.

 

 

table of content

29

---

 

9.  Related Party Transactions

 

Notes Receivable

 

Plantation Pipe Line Company

 

As of June 30, 2011, we had 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 outstanding note receivable balance as of that date was $80.7 million.  On July 20, 2011, we, ExxonMobil, and Plantation Pipe Line Company amended the term loan agreement covering this current note receivable we and ExxonMobil have from Plantation.  Together, we agreed to (i) reduce the aggregate loan amount to $100.0 million following payments of $57.9 million made by Plantation to ExxonMobil and us on July 20, 2011; (ii) extend the maturity of the note from July 20, 2011 to July 20, 2016; (iii) allow for pre-payment of all or any portion of the principal amount of the loan without a premium penalty; and (iv) revise the interest rate on the note from 4.72% per annum to 4.25% per annum.  Following the July 20, 2011 payments to both us and ExxonMobil, the note provides for semiannual payments of principal and interest on December 31 and June 30 each year beginning on December 31, 2011, with a final principal payment of $87.8 million due on July 20, 2016.

 

During the first nine months of 2011, we received combined principal repayments of $30.9 million, and as of September 30, 2011, our 51.17% portion of the outstanding principal amount of the note was $51.2 million.  We included $1.1 million of this note receivable balance within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheet, and the remaining outstanding balance within “Notes Receivable.”  As of 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 sheet.

 

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 September 30, 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 $108.4 million and $114.2 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.

 

River Consulting, LLC

 

In conjunction with the sale of our 51% equity ownership interest in River Consulting, LLC and Devco USA, L.L.C. (discussed in Note 2), we extended separate lines of credit to River Consulting and Devco, allowing them to borrow from us an aggregate amount of $3.0 million for working capital purposes.  The lines of credit expire on December 31, 2012, and provide for maximum advances of $2.7 million to River Consulting and $0.3 million to Devco.  Advances by us pursuant to these lines of credit are evidenced by notes that bear interest at the rate of 9.5% per annum.  The notes provide for monthly payments of interest and allow for prepayment of principal borrowings.  As of September 30, 2011, River Consulting   had borrowed $1.6 million under its line of credit agreement with us, and we included this receivable amount within “Notes receivable” on our accompanying consolidated balance sheet.

 

table of content

30

---

 

Other Receivables and Payables

 

As of September 30, 2011 and December 31, 2010, our related party receivables (other than notes receivable discussed above in “—Notes Receivable”) totaled $7.1 million and $15.4 million, respectively.  The September 30, 2011 receivables amount consisted of (i) $3.1 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $4.0 million of natural gas imbalance receivables included within “Other current assets.”  The $3.1 million receivable amount primarily consisted of amounts due from the Express pipeline system and from Plantation Pipe Line Company.  The $4.0 million natural gas imbalance receivable amount was due from 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.

 

As of September 30, 2011 and December 31, 2010, our related party payables totaled $11.0 million and $8.8 million, respectively.  The amounts consisted of (i) $7.1 million and $5.1 million, respectively, included within “Accounts payable” and primarily related to amounts due to KMI; and (ii) $3.9 million and $3.7 million of natural gas imbalance payables, respectively, 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 until July 20, 2011, 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.

 

Non-cash Compensation Expenses

 

In the first nine months of 2011 and 2010, KMI allocated to us certain non-cash compensation expenses totaling $89.9 million and $3.7 million, respectively.  The 2011 amount included an $87.1 million first quarter expense associated with a one-time special cash bonus payment that was paid to non-senior management employees in May 2011.  The remaining $2.8 million expense in 2011 and the $3.7 million expense in 2010 were both related to KMI’s May 2007 going–private transaction.  However, we do not have any obligation, nor do we expect to pay any amounts related to these 2011 and 2010 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 defined by U.S. generally accepted accounting principles) to us as of September 30, 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.

 

table of content

31

---

 

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 September 30, 2011 and December 31, 2010 (in millions):

 

		September 30, 2011				December 31, 2010
Derivatives – asset/(liability)
Current assets		$	36.7			$	-
Noncurrent assets		$	49.7			$	12.7
Current liabilities		$	(41.3	)		$	(221.4	)
Noncurrent liabilities		$	(11.3	)		$	(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 nine months ended September 30, 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 nine months ended September 30, 2011, and a description of any material events occurring subsequent to September 30, 2011, but before the filing of this report.

 

table of content

32

---

 

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; Navajo Refining Company, L.L.C. as Navajo; Holly Refining & Marketing Company LLC as Holly; 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; the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration as the PHMSA; the United States Environmental Protection Agency as the U.S. EPA; the New Jersey Department of Environmental Protection as the NJDEP; 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.

 

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 in March 2011 a wide range of rate challenges dating back to 1992 (Historical Cases Settlements).  Settlement payments were made to the eleven shippers in June 2010 and to Chevron in March 2011.

 

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 (since resolved) 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 settlement 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.

 

 

table of content

33

---

 

 

The following FERC dockets are currently pending:

 

▪

FERC Docket No. IS08-390 (West Line Rates) (Opinion 511)—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;

 

▪

FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, Western Refining, Navajo, Holly, 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 Opinion 511, it is not possible to predict the outcome of FERC or appellate review;

 

▪

FERC Docket No. IS11-444 (2011 Index Rate Increases)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines, Tesoro, Western Refining, Navajo, and Holly—Status:  SFPP withdrew all index rate increases except those that pertain to the West Line.  As to the West Line, the index rate increases are currently accepted and suspended, subject to refund, and the case is before a FERC hearing judge;

 

▪

FERC Docket No. IS11-585 (Withdrawal of 2011 Index Rate Increases)—Protestants: BP, ConocoPhillips, Valero Marketing, Chevron, the Airlines, Tesoro, Western Refining, Navajo, and Holly—Status:  SFPP withdrew all index rate increases except those that pertain to the West Line.  The Protestants have challenged the index ceiling levels for lines other than the West Line.  The protests and SFPP’s answer are currently pending before the FERC;

 

▪

FERC Docket No. OR11-13 (SFPP Base Rates)—Complainant:  ConocoPhillips—Status:  SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390.  ConocoPhillips permitted to amend its complaint based on additional data;

 

▪

FERC Docket No. OR11-14 (SFPP Indexed Rates)—Complainant:  ConocoPhillips—Status:  Complaint dismissed;

 

▪

FERC Docket No. OR11-15 (SFPP Base Rates)—Complainant:  Chevron—Status:  SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390.  Chevron permitted to amend its complaint based on additional data;

 

▪

FERC Docket No. OR11-16 (SFPP Indexed Rates)—Complainant:  Chevron—Status:  Complaint dismissed;

 

▪

FERC Docket No. OR11-18 (SFPP Base Rates)—Complainant:  Tesoro—Status:  SFPP to provide further data within 90 days of the issuance of a final order in Docket No. IS08-390.  Tesoro permitted to amend its complaint based on additional data; and

 

▪

FERC Docket No. OR11-19 (SFPP Indexed Rates)—Complainant:  Tesoro—Status:  Complaint dismissed.

 

▪

FERC Docket No. OR11-20 (SFPP North Line Base Rates)—Complainant:  Tesoro—Status:  Complaint was filed August 2, 2011.  SFPP answered on September 1, 2011.  Matter is currently pending before the FERC.

 

▪

FERC Docket No. OR12-1 (SFPP Index Ceiling Levels)—Complainant:  Chevron—Status:  Complaint was filed October 5, 2011.  SFPP answered on October 26, 2011.  Matter is currently pending before the FERC.

 

▪

FERC Docket No. OR12-2 (SFPP Index Ceiling Levels)—Complainant:  Tesoro—Status:  Complaint was filed October 5, 2011.  SFPP answered on October 26, 2011.  Matter is currently pending before the FERC.

 

▪

FERC Docket No. OR12-3 (SFPP Index Ceiling Levels)—Complainant:  ConocoPhillips—Status:  Complaint was filed October 5, 2011.  SFPP answered on October 26, 2011.  Matter is currently pending before the FERC.

 

With respect to the SFPP proceedings above and the Calnev proceedings discussed below, we estimate that the shippers are seeking approximately $50.0 million in annual rate reductions and $140.0 million in refunds.  However, applying the principles of Opinion 511, a full FERC decision on our West Line Rates, to these cases would result in substantially lower rate reductions and refunds.  In the first nine months of 2011, we recorded a $161.3 million expense and increased our litigation reserve related to these cases and the litigation discussed below involving SFPP and the CPUC.  We do not expect refunds in these cases to have an impact on our distributions to our limited partners.

 

table of content

34

---

 

 

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:

▪

FERC Docket Nos. OR07-7, OR07-18, OR07-19, OR07-22, OR09-15, and OR09-20 (consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status:  Before a FERC settlement judge.

 

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 reached a settlement in principle that will resolve all issues set for hearing.  On May 5, 2011, KMIGT filed a formal settlement document, referred to in this Note as the Settlement and which is supported or not opposed by all parties of record, and on September 22, 2011, the FERC approved the Settlement.

 

The Settlement resolves all issues in the proceeding and provides shippers on KMIGT’s system with prospective reductions in the fuel and gas and lost and unaccounted for rates, referred to as the Fuel Retention Factors, effective June 1, 2011.  The Settlement results in a 27% reduction in the Fuel Retention Factors billed to shippers effective June 1, 2011, as compared to the Fuel Retention Factors approved and in effect on March 1, 2011.  The Settlement also provides for a second stepped reduction, resulting in a total 30% reduction in the Fuel Retention Factors billed to shippers and effective January 1, 2012, for certain segments of the former Pony Express pipeline system.  Except for these reductions to the Fuel Retention Factors, other transportation and storage rates will not be altered by the Settlement.  

 

California Public Utilities Commission Proceedings

 

We have previously reported ratemaking and complaint proceedings against SFPP 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, which 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.  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. 

 

table of content

35

---

 

On May 26, 2011, the CPUC issued an order adopting the proposed decision, which would eliminate from SFPP’s transportation rates an allowance for income taxes on income generated by SFPP.  The order also calls for partial refund of rates charged to shippers that were previously deemed reasonable by the CPUC.  The order would only affect rates for SFPP’s intrastate pipeline service within the state of California and would have no effect on SFPP’s interstate rates, which do include such an allowance under orders of the FERC and opinions of the U.S. Court of Appeals for the District of Columbia.  On this same date, we announced that we will seek rehearing and pursue other legal options to overturn the CPUC’s order. 

 

On June 22, 2011, a CPUC administrative law judge (“ALJ”) issued a proposed decision substantially reducing SFPP’s authorized cost of service, requiring SFPP’s prospective rates to be reduced to reflect the authorized cost of service, and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service.  SFPP filed comments on the proposed decision on June 22, 2011, outlining what it believes to be errors in law and fact in the proposed decision, including the requirement that refunds be made from May 24, 2007.  By subsequent ruling of the ALJ, the referenced proposed decision has been withdrawn.  The ALJ ruling indicated that a revised proposed decision would be issued at an unspecified date, subject to comments from the parties and a request for oral argument before the full CPUC.

 

Based on our review of these CPUC proceedings and the shipper comments thereon, we estimate that the shippers are requesting approximately $360.0 million in reparation payments and approximately $ 30.0 million in annual rate reductions.  The actual amount of reparations will be determined through further proceedings at the CPUC and we believe that the appropriate application of the May 26, 2011 CPUC order and the June 22, 2011 administrative law decision will result in a considerably lower amount.  In addition, further procedural steps, including motions for rehearing and writ of review to California’s Court of Appeals, will be taken with respect to these decisions.  We do not expect any reparations that we would pay in these matters to have an impact on our distributions to our limited partners.

 

In September 2011, with respect to certain cases, we made refund payments of $18.4 million to various intrastate shippers pursuant to orders received from the CPUC.

 

Carbon Dioxide Litigation

 

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 filed petitions for a refund of the taxes paid under protest.  A hearing on our petition is scheduled for December 19, 2011 before the Montezuma County Board of County Commissioners.  Kinder Morgan CO 2   will vigorously contest the retroactive tax bills.

 

 

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.

 

table of content

36

---

 

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 v. 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 has concluded.  In September 2011, the judge determined that the annual rent payable as of January 1, 2004 is $14.8 million, subject to annual consumer price index increases.  SFPP intends to appeal the judge’s determination, but if that determination is upheld, SFPP would owe approximately $73.9 million in back rent.  Accordingly, in September 2011, we recorded a $73.9 million expense and increased our rights-of-way liability related to this legal matter.

 

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.  A trial with respect to these matters commenced in October 2011.  A decision is expected in the fourth quarter of 2011.

 

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, our results of operations, and our cash flows.  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.

 

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

 

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 properly manage the water level in the pit of a coker unit at a refinery owned by Premcor, failing to name Premcor as an additional insured, and failing to indemnify Premcor for claims brought against Premcor by PACC.  PACC is a wholly owned subsidiary of Premcor.  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 its refinery.  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 is also seeking to recover an additional $11.4 million of alleged losses and damages in excess of the amount it owes to PACC.  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.  The final arbitration hearing concluded on October 3, 2011.  On October 21, 2011, we received the arbitrator’s findings of fact and rulings of law, which determined that Kinder Morgan has no liability for damages with respect to the claims asserted by PACC in the prior arbitration or by Premcor in the present arbitration.

 

table of content

37

---

 

City of Reno, State of Nevada, et al. its Attorney General’s office v. SFPP, LP, Kinder Morgan Operating L.P. “D” and Kinder Morgan G.P. (Case No. CV09-02277 District Court of Washoe County, Nevada).

 

The City of Reno asserts claims against the Kinder Morgan defendants for breach of contract, fraud, and violations of the Nevada False Claims Act arising out of a construction project in Reno, Nevada in 2003.  The Kinder Morgan defendants were a general contractor for a pipeline relocation project and billed the City of Reno for the costs associated with the pipeline relocation.  The City of Reno paid those costs but later claimed that the Kinder Morgan defendants overcharged the City for the project.  The City seeks damages of approximately $4 million for the alleged overcharge plus treble damages under the Nevada False Claims Act.  The Kinder Morgan defendants deny these allegations.  The case will be set for trial in 2012.

 

South Central Cement, Ltd. v. River Consulting, LLC and CCC Group, Inc., Cause No. 2009-50242 in the District Court of the 61 st Judicial District, Harris County, Texas.

 

South Central Cement, Ltd. (SCC) filed suit against CCC Group, Inc. (CCC) and our affiliate, River Consulting, LLC (RCI) alleging claims for negligence and breach of contract in connection with the design and construction of two warehouses and interior retaining walls to store bulk cement, referred to in this Note as the Facilities.  SCC alleges that the retaining walls collapsed due to faulty design by RCI and/or construction by CCC.  SCC has alleged that its damages, including repair or replacement costs and lost profits, exceed $7.5 million.  RCI filed a motion for partial summary judgment to enforce contractual waivers limitations on damages.  By order dated October 29, 2010, the trial court ordered that (i) defendant RCI’s potential aggregate liability, if any, to plaintiff for damages in this matter is limited to a maximum of $50,000 in tort pursuant to the terms of the agreement between the parties; and (ii) plaintiff has by agreement waived all claims in both tort and contract related to lost profits, reduced handling capacity, or other consequential damages.  Despite the issuance of the partial summary judgment order in favor of RCI, SCC has persisted in its claim against both RCI and CCC and has continued to assert a purported claim for “direct damages” in excess of $7.0 million, which SCC has alleged is the cost to repair, rebuild or replace the Facilities.  Defendants estimate that the replacement cost of the Facilities is approximately $1 million.  The matter is set for trial for the term of court beginning February 27, 2012.

 

General Litigation Matters

 

Rick Lewis v. Kinder Morgan Energy Partners, L.P., et al (Case No. A566869 District Court Clark County, Nevada).

 

The plaintiff’s estate asserts claims for wrongful death arising out of the deceased’s alleged exposure to gasoline at Kinder Morgan’s Las Vegas Terminal from 2002 to 2008.  During this time period, the deceased was employed as a tanker truck driver at Williams Trucking and he loaded gasoline at the Kinder Morgan Terminal.  Plaintiff alleges that Kinder Morgan failed to provide a safe premise by exposing the deceased to gasoline while he completed his loading operations and that Kinder Morgan distributed a defective product (gasoline).  The plaintiff’s estate and survivors seek damages for his medical bills, loss of future income, pain and suffering, and past and future loss of companionship.  The trial of this case concluded on October 10, 2011.  The jury returned a verdict against Kinder Morgan Energy Partners for $7.5 million.  Further procedural steps, including a motion for new trial and an appeal to the Nevada Supreme Court, will be taken if warranted.

 

Mine Safety Matters

 

In the third quarter of 2011, our bulk terminals operations that handle coal received five 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 (none of which was under section 104(d) or section 104(b) of the act).  The aggregate of proposed assessments outstanding in respect of all citations received under the act in 2011, as of September 30, was $3,888.  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.

 

table of content

38

---

 

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.  On September 13, 2011, the court granted preliminary approval to a proposed settlement of $2.2 million for a proposed settlement class of approximately 400 current and former employees.  A final hearing on the proposed class action settlement will be held in the first quarter of 2012.

 

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.  Calnev and the Navy entered into an Administrative Settlement Agreement effective October 4, 2011 pursuant to which Calnev reimbursed the Navy  $0.5 million in past response costs under the federal Comprehensive Environmental Response, Compensation and Liability Act (referred to in this Note as CERCLA).  

 

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.

 

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.   On October 3, 2011, our subsidiary, Trans Mountain L.P., and each of the City of Burnaby’s contractor and engineering consultant agreed to enter a plea of guilty to one count of The Environmental Management Act.  Each party agreed to pay a $1,000 fine and will contribute $149,000 into a B.C. environmental trust fund to be used for projects that benefit the environment and wildlife.  In addition, Trans Mountain agreed to donate $100,000 to BC Common Ground Alliance to further develop and deliver education to contractors for working safely around pipelines.  The Court has taken the matter under advisement and is expected to rule on November 10, 2011.

 

table of content

39

---

 

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.

 

Perth Amboy, New Jersey Tank Release

 

In May 2011, the PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order, or NOPV, to KMLT.  The notice alleges violations of PHMSA’s regulations related to an October 28, 2009 tank release from our Perth Amboy, New Jersey liquids terminal.  No product left the company’s property, and additionally, there were no injuries, no impact to the adjacent community or public, and no fire as a result of the release.  The notice proposes a penalty in the amount of $425,000.  We are cooperating fully with the PHMSA on the response and remediation of this issue.

 

Central Florida Pipeline Release, Tampa, Florida

 

On July 22, 2011, our subsidiary Central Florida Pipeline LLC reported a refined petroleum products release on a section of its 10-inch diameter pipeline near Tampa, Florida.  The pipeline carries jet fuel and diesel to Orlando and was carrying jet fuel at the time of the incident.  There was no fire and no injuries associated with the incident.  We immediately began clean up operations in coordination with federal, state and local agencies.  The cause of the incident is under investigation. 

 

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 reasonably 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 September 30, 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 $325.2 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 both payments of $81.4 million (for interstate and California intrastate transportation rate settlements on our Pacific operations’ pipelines) in the first nine months of 2011 that reduced the liability, and a $241.9 million increase in expense in the first nine months of 2011, which increased the liability.  We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.

 

 

table of content

40

---

 

Environmental Matters

 

New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division – Essex County, Docket No. L-9868-05.

 

The NJDEP sued Occidental Chemical and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers.  Occidental et al. then brought in approximately 300 third party defendants for contribution.  NJDEP claimed damages related to forty years of discharges of TCDD (form of dioxin), DDT and “other hazardous substances.”  GATX Terminals Corporation (n/k/a/ KMLT) was brought in as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (former GATX Terminals facility) is located on the Arthur Kill River, one of the waterways included in the litigation.  This case was filed against third party defendants in 2009.  The Judge issued his trial plan for this case during the first quarter of 2011.  According to the trial plan, he allowed the State to file summary judgment motions against Occidental, Maxus and Tierra on liability issues immediately.  Numerous third party defendants filed motions to dismiss, which were denied, and now have filed interlocutory appeals from those motions.  KMLT is part of the third party defendant Joint Defense Group.  We have filed an Answer and initial disclosures.  The Judge put off trial of Maxus/Tierra’s claims against the third party defendants until April 2013 with damages to be tried in September 2013.

 

Portland Harbor Superfund Site, Willamette River, Portland, Oregon.

 

In December 2000, the U.S. EPA sent out General Notice letters to potentially responsible parties (PRPs) including GATX Terminals Corporation (n/k/a KMLT).  At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor.  Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA.  The major PRPs formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group.  The LWG agreed to conduct the Remedial Investigation and Feasibility Study leading to the proposed remedy for cleanup of the Portland Harbor site.  Once the U.S. EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision.   Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs.  This is a non-judicial allocation process.  We are participating in the allocation process on behalf of both KMLT and KMBT.  Each entity has two facilities located in Portland Harbor.  We expect the allocation to conclude in 2013 or 2014, depending upon when the Record of Decision is issued by the U.S. EPA.

 

Roosevelt Irrigation District v. Kinder Morgan G.P., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona.

 

This is a CERCLA case brought against a number of defendants by a water purveyor whose wells have allegedly been contaminated due to the presence of number of contaminants.  The Roosevelt Irrigation District is seeking up to $175 million from approximately 70 defendants.  The plume of contaminates has traveled under Kinder Morgan’s Phoenix Terminal.  The plaintiffs have advanced a novel theory that the releases of petroleum from the Phoenix Terminal (which are exempt under the petroleum exclusion under CERCLA) have facilitated the natural degradation of certain hazardous substances and thereby have resulted in a release of hazardous substances regulated under CERCLA.  We are part of a joint defense group consisting of other terminal operators at the Phoenix Terminal including Chevron, BP, Salt River Project, Shell and a number of others, collectively referred to as the terminal defendants.  Together, we filed a motion to dismiss all claims based on the petroleum exclusion under CERCLA.  This case was recently assigned to a new judge, who has deemed all previous motions withdrawn and will grant leave to re-file such motions at a later date.  We plan to re-file the motion to dismiss as well as numerous summary judgment motions.

 

Y & S Enterprises v. Kinder Morgan Energy Partners, L.P., California Superior Court, Los Angeles, California.

 

The plaintiffs own property adjacent to the former KMLT Gaffey Street Terminal.  Plaintiffs allege that contamination from the Terminal migrated onto their property.  The Gaffey Street site has been remediated and sold to developers for construction of single family residences.  Currently, the plaintiffs and KMLT have contracted with a third party consultant to conduct soil and groundwater investigations on the plaintiffs’ property.  We expect the majority of contamination at the Y & S property is due to their own contamination.  Plaintiffs have not stated an alleged damages amount in their complaint or in discovery.

 

Casper and Douglas, EPA Notice of Violation

 

In March 2011, the EPA conducted inspections of several environmental programs at the Douglas and Casper Gas Plants in Wyoming.  In June 2011, we received two letters from the EPA alleging violations at both gas plants of the Risk Management Program requirements under the Clean Air Act.  We are cooperating with the EPA and working with the EPA to resolve these allegations.

table of content

41

---

 

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. At the next case management conference held on June 13, 2011, the judge again continued the full litigation stay.  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 water board.  The state water board has not yet taken any action with regard to our appeal petitions.

 

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 NJDEP, 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 Exxon Mobil 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 NJDEP for settlement of the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment which was subject to public notice and comment and court approval. The 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.  Simultaneously, KMLT and Plains Products entered into a settlement agreement that settled each parties’ relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final.  Now Plains will begin conducting remediation activities at the site and KMLT will provide oversight and 50% of the costs.  The settlement with the state does not resolve the original complaint brought by ExxonMobil, however we are now approaching settlement discussions with ExxonMobil. There is no trial date set.

 

table of content

42

---

 

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.

 

The Court issued a Case Management Order on January 6, 2011, setting dates for completion of discovery and setting a trial date. In April, 2011, the parties filed a joint stipulation to extend the discovery schedule by approximately 3 months. Now, the parties must complete all fact discovery by January 23, 2012.  A mandatory settlement conference is now set for November 2, 2011 and the trial is set for September 25, 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.

 

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 we are engaged in discussions with EPA SDD with the goal of 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, 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, financial position, results of operations or cash flows.

 

table of content

43

---

 

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.

 

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 September 30, 2011, we have accrued an environmental reserve of $76.9 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 September 30, 2011, we have recorded a receivable of $5.4 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

 

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 facilities is $18.4 million.  The project was constructed and went into service on April 14, 2011.

 

FERC Natural Gas Fuel Tracker Proceedings

 

Trailblazer Pipeline Company LLC

 

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 required Trailblazer to make a compliance filing for its annual Expansion Fuel Adjustment Percentage (EFAP) pursuant to its tariff.  In its previous 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 the Docket No. RP11-1939 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.  Trailblazer has filed for rehearing of the FERC’s April 28, 2011 order, which is pending before the FERC.

 

On May 2, 2011, Trailblazer filed to re-determine its EFAP in compliance with the April 28, 2011 order, implementing a revised EFAP rate of 8.14%, which included the proposed recovery of the deferred account.  On May 18, 2011, the FERC issued an order rejecting the May 2, 2011 filing, on the basis that the filing to implement a revised EFAP must be accomplished as a new proceeding, not as a compliance filing.  Trailblazer has filed for rehearing of the May 18, 2011 order, which is also pending before the FERC.

 

table of content

44

---

 

On June 3, 2011, Trailblazer filed in a new proceeding, Docket No. RP11-2168-000, revised tariff records to redetermine its EFAP, with a proposed effective date of July 1, 2011.  Trailblazer included three EFAP rate options.  In addition, under two of the options, Trailblazer proposed to continue to defer collection of the deferred account until a future date.  In an order dated July 1, 2011, referred to in this Note as the July 1 Order, the FERC rejected the two options to defer recovery of the deferred account and accepted the option that included recovery of the entire deferred account.  Specifically, the FERC approved an EFAP rate of 8.69%, subject to refund, effective July 1, 2011 and established hearing proceedings to determine the appropriate throughput, revenue and cost data to use for determining the EFAP and the composition, accounting and proposed recovery methodology for amounts in the deferred account.  In the July 1 Order, the FERC determined that Trailblazer could not charge negotiated rate shippers a fuel rate above the caps established in their negotiated rate agreements with Trailblazer and that operation of the cap was not an issue for hearing.  As a result of this determination, Trailblazer recognized a $13.1 million operating expense in the second quarter of 2011 for the amount of the deferred costs that is potentially attributable to the negotiated rate shippers.  Trailblazer sought rehearing of the July 1 Order, and a prehearing conference held on July 14, 2011 established a procedural schedule that results in a hearing in April 2012.  Trailblazer continues to pursue full recovery of the amount reserved pursuant to the Docket No. RP11-2168-000 proceeding.  Trailblazer has been engaged in settlement discussions with the active parties to this proceeding and has reached an agreement in principle with such parties.  As a result, on October 7, 2011, Trailblazer filed a motion to suspend the procedural schedule for 15 days to allow the parties to resolve the remaining issues in this proceeding and avoid the need for a hearing.  The Chief Judge granted Trailblazer’s motion to suspend the procedural schedule and required a status report on the timing for filing the settlement by October 28, 2011.  Given that the parties continue to finalize the settlement documents, Trailblazer will file to continue to suspend the procedural schedule for another 15-day period.  Upon execution of the necessary settlement documents, Trailblazer will file a motion to terminate the hearing procedure.

 

On July 25, 2011, Trailblazer filed, in Docket No. RP11-2295-000, to apply the EFAP rate to additional classes of shippers, including interruptible transportation, backhaul transportation, and overrun transportation to be  effective September 1, 2011.  On August 31, 2011, the FERC issued an order rejecting Trailblazer’s proposed tariff records on the basis that the tariff changes are contrary to Trailblazer’s Docket No. RP10-492-000 Settlement and violate the prohibition against retroactive ratemaking by proposing to charge shippers for under-recoveries that occurred prior to the effective date of the tariff provision.  Trailblazer has filed for rehearing of the August 31, 2011 order, which is pending before the FERC.  Furthermore, Trailblazer does not expect the entire fuel tracker proceedings discussed above to have a material adverse impact on its business, financial position, results of operations or cash flows.

 

Rockies Express Pipeline LLC

 

On March 1, 2011, Rockies Express Pipeline LLC made its annual filing to revise its fuel lost and unaccounted for percentage, referred to as its FL&U rate, applicable to its shippers effective April 1, 2011.  In this filing, Rockies Express requested an increase in its FL&U rate due to a decline in the price of natural gas used to index its FL&U rate that had resulted in a fuel tracker receivable balance as of December 31, 2010.  Rockies Express proposed two options to allow it to recover these costs.

 

On March 30, 2011, the FERC notified Rockies Express that it had rejected the first option and that the second option, while accepted effective April 1, 2011, was under further FERC review.  This event caused Rockies Express to reconsider the recoverability of a portion of its fuel tracker receivable balance that would have been recovered from one shipper. Therefore, in the first quarter of 2011, Rockies Express reduced its fuel tracker receivable balance by $8.2 million and  recorded the same amount as additional operations and maintenance expense.

 

 

 

table of content

45

---

 

 

12.  Recent Accounting Pronouncements

 

Accounting Standards Updates

 

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

 

ASU No. 2011-04

 

On May 12, 2011, the Financial Accounting Standards Board (FASB) issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.”  This ASU amends U.S. generally accepted accounting principles (GAAP) and results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and international financial reporting standards (IFRS).  The amendments in this ASU change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements; however, the amendment’s requirements do not extend the use of fair value accounting, and for many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the requirements in the “Fair Value Measurement” Topic of the Codification.  Additionally, ASU No. 2011-04 includes some enhanced disclosure requirements, including an expansion of the information required for Level 3 fair value measurements.  ASU No. 2011-04 is effective for interim and annual periods beginning on or after December 15, 2011 (January 1, 2012 for us).  The amendments in this ASU are to be applied prospectively, and early adoption is prohibited.  We are currently reviewing the effects of ASU No. 2011-04.

 

ASU No. 2011-05

 

On June 16, 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income.”  This ASU eliminates the current option to report other comprehensive income and its components in the statement of changes in equity (statement of partners’ capital for us).  An entity can elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive, statements.  ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 (January 1, 2012 for us) and interim and annual periods thereafter.  Early adoption is permitted, and full retrospective application is required.  Since this ASU pertains to disclosure requirements only, the adoption of this ASU will not have a material impact on our consolidated financial statements.

 

ASU No. 2011-08

 

On September 15, 2011, the FASB issued ASU No. 2011-8, “Testing Goodwill for Impairment.”  This ASU allows an entity to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test prescribed by current accounting principles.  However, the quantitative impairment test is required if an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount.  An entity can choose to perform the qualitative assessment on none, some or all of its reporting units.  Moreover, an entity can bypass the qualitative assessment for any reporting unit in any period and proceed directly to the quantitative goodwill impairment test, and then resume performing the qualitative assessment in any subsequent period.  ASU No. 2011-8 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 (January 1, 2012 for us), and early adoption is permitted.  We performed our 2011 annual goodwill impairment test on May 31, and we are currently reviewing the effects of ASU No. 2011-8.

 

ASU No. 2011-09

 

On September 21, 2011, the FASB issued ASU No. 2011-9, “Compensation – Retirement Benefits – Multiemployer Plans (Subtopic 715-80).”  The amendments in this ASU require that employers provide, on an annual basis, additional separate disclosures for all individually significant multiemployer pension plans and multiemployer other postretirement benefit plans.  The revisions do not change the current recognition and measurement guidance for an employer’s participation in a multiemployer plan.  ASU No. 2011-9 is effective for fiscal years ending after December 15, 2011 (December 31, 2011 for us).  Early adoption is permitted and retrospective application is required.  We are currently reviewing the effects of ASU No. 2011-9.

 

table of content

46

---

 

 

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); (ii) our consolidated financial statements and related notes included in our 2010 Form 10-K/A; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 2010 Form 10-K.

 

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 primarily has contracts with minimum volume requirements, which as of December 31, 2010, had a remaining average contract life of 4.7 years.  Carbon dioxide sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed.  Older contracts have had a fixed price component and a variable price component typically tied to the price of crude oil.  More recent contracts have provided for a delivered price tied to the price of crude oil, but with a floor price.  On a volume-weighted basis, for contracts making deliveries in 2011, and utilizing the average oil price per barrel contained in our 2011 budget, approximately 76% of our contractual volumes are based on a fixed fee or floor price, 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 $70.43 and $69.54 per barrel in the third quarter and first nine months of 2011, respectively, and $59.54 and $59.88 per barrel in the third quarter and first nine months of 2010, respectively.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $87.73 and $92.71 per barrel in the third quarter and first nine months of 2011, respectively, and $73.74 and $75.12 per barrel in the third quarter and first nine months of 2010, respectively.

 

table of content

47

---

 

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 these capital investments 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 currently estimate spending approximately $2.4 billion for our 2011 capital expansion program, including acquisitions and investment contributions (effective July 1, 2011, we acquired the remaining 50% interest in KinderHawk Field Services LLC that we did not already own and a 25% interest in EagleHawk Field Services LLC for an aggregate consideration of $912.1 million).  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 nine months of 2011, please see “—Financial Condition” below.

 

 

table of content

48

---

 

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.

 

Furthermore, with regard to goodwill impairment testing, we review our goodwill for impairment annually, and we evaluated our goodwill for impairment on May 31, 2011.  Our goodwill impairment analysis performed on that date did not result in an impairment charge, and subsequent to that date, no event has occurred 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.  For more information on our goodwill impairment analysis, see Note 3 “Intangibles—Goodwill” to our consolidated financial statements included elsewhere in this report.

 

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 nine months ended September 30, 2011.

 

Results of Operations

 

Consolidated

 

		Three Months Ended September 30,								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)		$	102.7			$	167.5			$	(64.8	)			(39	)%
Natural Gas Pipelines(c)			80.8				187.3				(106.5	)			(57	)%
CO 2 (d)			294.8				221.5				73.3				33	%
Terminals(e)			179.8				159.2				20.6				13	%
Kinder Morgan Canada			48.5				44.0				4.5				10	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments			706.6				779.5				(72.9	)			(9	)%
Depreciation, depletion and amortization expense			(253.4	)			(224.1	)			(29.3	)			(13	)%
Amortization of excess cost of equity investments			(1.8	)			(1.4	)			(0.4	)			(29	)%
General and administrative expense(f)			(100.5	)			(93.6	)			(6.9	)			(7	)%
Interest expense, net of unallocable interest income(g)			(132.5	)			(133.8	)			1.3				1	%
Unallocable income tax expense			(2.1	)			(4.2	)			2.1				50	%
Net income			216.3				322.4				(106.1	)			(33	)%
Net income attributable to noncontrolling interests(h)			(1.8	)			(1.6	)			(0.2	)			(13	)%
Net income attributable to Kinder Morgan Energy Partners, L.P.		$	214.5			$	320.8			$	(106.3	)			(33	)%

____________

		Nine Months Ended September 30,								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(i)		$	303.9			$	339.1			$	(35.2	)			(10	)%
Natural Gas Pipelines(j)			484.7				592.9				(108.2	)			(18	)%
CO 2 (k)			823.2				724.1				99.1				14	%
Terminals(l)			524.5				475.2				49.3				10	%
Kinder Morgan Canada(m)			150.0				132.9				17.1				13	%
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments			2,286.3				2,264.2				22.1				1	%
Depreciation, depletion and amortization expense			(704.6	)			(674.6	)			(30.0	)			(4	)%
Amortization of excess cost of equity investments			(4.9	)			(4.3	)			(0.6	)			(14	)%
General and administrative expense(n)			(387.1	)			(288.1	)			(99.0	)			(34	)%
Interest expense, net of unallocable interest income(o)			(393.8	)			(373.9	)			(19.9	)			(5	)%
Unallocable income tax expense			(6.8	)			(8.4	)			1.6				19	%
Net income			789.1				914.9				(125.8	)			(14	)%
Net income attributable to noncontrolling interests(p)			(6.3	)			(7.6	)			1.3				17	%
Net income attributable to Kinder Morgan Energy Partners, L.P.		$	782.8			$	907.3			$	(124.5	)			(14	)%

____________

 

 

table of content

49

---

 

 

(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 $69.3 million increase in expense primarily related to an adverse tentative court decision on the amount of rights-of-way lease payment obligations (amounts included in the $69.3 million relate to periods prior to 2011), and a $5.6 million increase in expense associated with environmental liability adjustments.  2010 amount includes a $2.5 million increase in expense associated with environmental liability adjustments, and a $1.9 million increase in property environmental expense related to the retirement of our Gaffey Street, California land.  2011 and 2010 amounts also include a $0.3 million decrease in income and a $0.3 million increase in income, respectively, from unrealized foreign currency gains and losses on long-term debt transactions.
(c)	2011 amount includes a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.  2010 amount includes a $1.6 million decrease in income from unrealized losses on derivative contracts used to hedge forecasted natural gas sales.
(d)	2011 and 2010 amounts include an $8.5 million increase in income and a $7.9 million decrease in income, respectively, from unrealized gains and losses on derivative contracts used to hedge forecasted crude oil sales.
(e)	2011 amount includes (i) a $1.2 million increase in expense from casualty insurance deductibles; (ii) a combined $0.5 million decrease in income from property write-offs and expenses associated with the dissolution of our partnership interest in Globalplex Handling; (iii) a $0.2 million decrease 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; and (iv) a $1.3 million increase in income from the sale of our ownership interest in Arrow Terminals B.V.  2010 amount includes a $5.0 million increase in expense from casualty insurance deductibles, and a $0.2 million decrease in expense from certain measurement period adjustments related to our March 5, 2010 Slay Industries terminal acquisition.
(f)	2011 amount includes a $0.2 million decrease in unallocated payroll tax expense (related to the $87.1 million special non-cash bonus expense to non-senior management employees allocated to us from KMI in the first quarter of 2011 (however, we do not have any obligation, nor do we expect to pay any amounts related to this expense), a $0.1 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season, and a $0.3 million increase in expense for certain legal expenses associated with business acquisitions.  2010 amount includes a $1.0 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).  2011 and 2010 amounts also include increases in expense of $0.1 million and $1.1 million, respectively, for certain asset and business acquisition costs.
(g)	2011 and 2010 amounts include increases in imputed interest expense of $0.1 million and $0.2 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
(h)	2011 and 2010 amounts include decreases of $3.0 million and $1.9 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.
(i)	2011 amount includes (i) a $234.3 million increase in expense primarily associated with adjustments to rate case reserves and rights-of-way lease payment obligations; (ii) a $5.6 million increase in expense associated with environmental liability adjustments; (iii) a $10.8 million increase in income from the sale of a portion of our Gaffey Street, California land; and (iv) a $0.1 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 or realize any direct benefits related to this expense).  2010 amount includes a $158.0 million increase in expense associated with rate case liability adjustments, a $17.4 million decrease in income associated with combined property environmental expenses and disposal losses related to the demolition of physical assets in preparation for the sale of our Gaffey Street, California land, and a $2.5 million increase in expense associated with environmental liability adjustments.  2011 and 2010 amounts also include a $0.1 million decrease in income and a $0.4 million increase in income, respectively, from unrealized foreign currency gains and losses on long-term debt transactions.

 

table of content

50

---

 

 

(j)	2011 amount includes a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value, and a $9.7 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  2010 amount includes a $0.8 million decrease in income from unrealized losses 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.
(k)	2011 and 2010 amounts include increases in income of $10.4 million and $5.4 million, respectively, from unrealized gains on derivative contracts used to hedge forecasted crude oil sales.
(l)	2011 amount includes (i) a $4.7 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 or realize any direct benefits related to this expense); (ii) a $4.3 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (iii) a $2.2 million increase in income associated with the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.; (iv) a $2.0 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; (v) a $1.3 million increase in income from the sale of our ownership interest in Arrow Terminals B.V.; (vi) a $4.4 million decrease in income from casualty insurance deductibles and the write-off of assets related to casualty losses; (vii) a $1.2 million increase in expense associated with environmental liability adjustments; (viii) a $0.6 million increase in expense associated with the settlement of a litigation matter at our Carteret, New Jersey liquids terminal;  and (ix) a combined $0.5 million decrease in income from property write-offs and expenses associated with the dissolution of our partnership interest in Globalplex Handling. 2010 amount includes (i) a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal; (ii) a $0.2 million decrease in expense from certain measurement period adjustments related to our March 5, 2010 Slay Industries terminal acquisition; (iii) a $5.0 million increase in expense from casualty insurance deductibles; and (iv) a $0.6 million increase in expense related to storm and flood clean-up and repair activities.
(m)	2011 amount includes a $2.2 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 or realize any direct benefits related to this expense).
(n)	2011 amount includes (i) a combined $89.9 million increase in non-cash compensation expense (including $87.1 million related to a special bonus expense to non-senior management employees), allocated to us from KMI; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense; (ii) a $1.2 million increase in expense for certain asset and business acquisition costs; (iii) a $1.2 million increase in unallocated payroll tax expense (related to the $87.1 million special bonus expense allocated to us from KMI); (iv) a $0.3 million increase in expense for certain legal expenses associated with business acquisitions; and (v) a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.  2010 amount includes (i) a $3.7 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); (ii) a $3.5 million increase in expense for certain asset and business acquisition costs; (iii) a $1.6 million increase in legal expense associated with items disclosed in these footnotes such as legal settlements and pipeline failures; and (iv) a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.
(o)	2011 and 2010 amounts include increases in imputed interest expense of $0.5 million and $0.8 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
(p)	2011 and 2010 amounts include decreases of $6.5 million and $4.3 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the nine month 2011 and 2010 items previously disclosed in these footnotes.

 

Net income attributable to our partners (which includes all of our limited partner unitholders and our general partner) totaled $214.5 million for the three months ended September 30, 2011.  This compares to net income attributable to our partners of $320.8 million for the three months ended September 30, 2010.  For the nine months ended September 30, 2011 and 2010, net income attributable to our partners totaled $782.8 million and $907.3 million, respectively.  We earned total revenues of $2,195.1 million and $2,060.0 million, respectively, in the three month periods ended September 30, 2011 and 2010, and revenues of $6,207.2 million and $6,151.1 million, respectively, in the nine month periods ended September 30, 2011 and 2010.

 

table of content

51

---

 

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.

 

Compared to the third quarter of 2010, total segment earnings before depreciation, depletion and amortization decreased $72.9 million (9%) in the third quarter of 2011; however, this overall decrease in earnings included a $216.1 million decrease in earnings from the effect of the certain items described in the footnotes to the tables above (which combined to decrease total segment EBDA by $234.5 million in the third quarter of 2011 and to decrease total segment EBDA by $18.4 million in the third quarter of 2010).  The remaining $143.2 million (18%) increase in quarterly segment earnings before depreciation, depletion and amortization included higher earnings in 2011 from all five of our reportable business segments, mainly due to increases attributable to our Natural Gas Pipelines and CO 2 business segments.

 

For the comparable nine month periods, total segment earnings before depreciation, depletion and amortization expenses remained essentially flat, increasing by $22.1 million (1%) in 2011 compared to 2010; however, this overall increase in earnings included a decrease of $214.4 million from the effect of the certain items described in the footnotes to the table above (which combined to decrease total segment EBDA by $385.6 million in the first nine months of 2011 and to decrease total segment EBDA by $171.2 million in the first nine months of 2010).  The remaining $236.5 million (10%) 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 CO 2 , Natural Gas Pipelines, and Terminals business segments.

 

Products Pipelines

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions, except operating statistics)
Revenues		$	241.6			$	227.7			$	694.6			$	661.5
Operating expenses(a)			(146.8	)			(67.8	)			(425.8	)			(341.7	)
Other income (expense)(b)			(0.2	)			(0.1	)			10.4				(4.0	)
Earnings from equity investments			12.6				7.6				35.4				22.2
Interest income and Other, net(c)			0.4				2.1				3.9				6.0
Income tax expense(d)			(4.9	)			(2.0	)			(14.6	)			(4.9	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	102.7			$	167.5			$	303.9			$	339.1
Gasoline (MMBbl)(e)			101.7				102.2				297.2				299.4
Diesel fuel (MMBbl)			37.2				38.4				110.7				109.5
Jet fuel (MMBbl)			28.1				27.1				82.9				78.1
Total refined product volumes (MMBbl)			167.0				167.7				490.8				487.0
Natural gas liquids (MMBbl)			7.6				6.7				19.8				18.3
Total delivery volumes (MMBbl)(f)			174.6				174.4				510.6				505.3
Ethanol (MMBbl)(g)			8.0				7.6				23.0				22.4

____________

 

table of content

52

---

 

 

(a)	Three and nine month 2011 amounts include increases in expense of $69.3 million and $234.3 million, respectively, primarily associated with adjustments to rate case reserves and rights-of-way lease payment obligations, and a $5.6 million increase in expense associated with environmental liability adjustments.  Three and nine month 2010 amounts include increases in expense of $2.5 million associated with environmental liability adjustments, and increases in expense of $1.9 million and $13.5 million, respectively, associated with environmental clean-up expenses and the demolition of physical assets in preparation for the sale of our Gaffey Street, California land.  Nine month 2010 amount also includes a $158.0 million increase in expense associated with rate case liability adjustments.
(b)	Nine month 2011 amount includes a $10.8 million increase in income from the sale of a portion of our Gaffey Street, California land.  Nine month 2010 amount includes property disposal losses of $3.9 million related to the demolition of physical assets in preparation for the sale of our Gaffey Street, California land.
(c)	Three and nine month 2011 amounts include decreases in income of $0.3 million and $0.1 million, respectively, and three and nine month 2010 amounts include increases in income of $0.3 million and $0.4 million, respectively, all resulting from unrealized foreign currency gains and losses on long-term debt transactions.
(d)	Nine month 2011 amount includes a $0.1 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 or realize any direct benefits related to this expense).
(e)	Volumes include ethanol pipeline volumes.
(f)	Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.
(g)	Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

Combined, the certain items described in the footnotes to the table above accounted for decreases in segment earnings before depreciation, depletion and amortization expenses of $71.1 million in the third quarter of 2011, and $51.6 million in the first nine months of 2011, when compared to the same two periods of 2010.  Following is information, for each of the comparable three and nine month periods of 2011 and 2010, related to the segment’s (i) remaining $6.3 million (4%) and $16.4 million (3%) increases in earnings before depreciation, depletion and amortization; and (ii) $13.9 million (6%) and $33.1 million (5%) increases in operating revenues:

 

Three Months Ended September 30, 2011 versus Three Months Ended September 30, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Cochin Pipeline		$	8.0				77	%		$	14.2				108	%
Plantation Pipeline			3.4				31	%			0.4				7	%
Southeast Terminals			2.5				18	%			4.8				24	%
West Coast Terminals			1.9				10	%			1.9				7	%
Central Florida Pipeline			0.5				4	%			(0.8	)			(5	)%
Pacific operations			(8.5	)			(11	)%			(4.2	)			(4	)%
Calnev Pipeline			(0.6	)			(4	)%			-				-	%
All others (including eliminations)			(0.9	)			(9	)%			(2.4	)			(17	)%
Total Products Pipelines		$	6.3				4	%		$	13.9				6	%

____________

Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Cochin Pipeline		$	18.1				77	%		$	26.1				79	%
Plantation Pipeline			6.7				20	%			0.7				5	%
West Coast Terminals			5.8				10	%			8.0				11	%
Southeast Terminals			0.5				1	%			8.3				12	%
Pacific operations			(4.1	)			(2	)%			(3.4	)			(1	)%
Central Florida Pipeline			(3.9	)			(9	)%			(1.6	)			(3	)%
Calnev Pipeline			(3.8	)			(9	)%			(3.2	)			(6	)%
All others (including eliminations)			(2.9	)			(9	)%			(1.8	)			(5	)%
Total Products Pipelines		$	16.4				3	%		$	33.1				5	%

 

table of content

53

---

 

The primary increases and decreases in our Products Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in the comparable three and nine month periods of 2011 and 2010 included the following:

 

▪

increases of $8.0 million (77%) and $18.1 million (77%), respectively, due to higher earnings from our Cochin natural gas liquids pipeline system.  The earnings increases were driven by system-wide increases in throughput volumes of 53% and 48%, respectively, due to increased demand for both terminal and storage deliveries on the pipeline’s West leg (U.S.), higher customer demand on the pipeline’s East leg (Canadian), and for the comparable nine month periods, to the exercise of a certain shipper incentive tariff offered in the first quarter of 2011 ;

 

▪

increases of $3.4 million (31%) and $6.7 million (20%), respectively, from our 51%-owned Plantation pipeline system.  Plantation benefitted from higher oil loss allowance revenues and higher mainline transportation revenues, and for the comparable nine month periods, the absence of an expense from the write-off of an uncollectible receivable in the first quarter of 2010;

 

▪

increases of $2.5 million (18%) and $0.5 million (1%), respectively, from our Southeast terminal operations.  The increases were due to strong third quarter 2011 results, driven by higher product inventory gains and higher revenues from ethanol and other blending services, relative to the third quarter of 2010;

 

▪

increases of $1.9 million (10%) and $5.8 million (10%), respectively, from our West Coast terminal operations.  The increases in terminal earnings were mainly due to the completion of various terminal expansion projects that increased liquids tank capacity since the end of the third quarter of 2010 and to higher rates on existing storage;

 

▪

an increase of $0.5 million (4%) and a decrease of $3.9 million (9%), respectively, from our Central Florida Pipeline.  Earnings from our Central Florida pipeline system were flat across both comparable quarterly periods, but decreased in the comparable nine month periods largely due to a 12% drop in pipeline delivery volumes, due primarily to weaker demand and to the incremental business of a competing terminal in Florida;

 

▪

decreases of $8.5 million (11%) and $4.1 million (2%), respectively, from our Pacific operations.  The decrease in earnings for the comparable third quarter periods was largely due to a $7.6 million increase in operating expense related to an adverse tentative court decision on the amount of 2011 rights-of-way lease payment obligations.  The decrease in earnings for the comparable nine month periods was primarily due to a drop in mainline delivery revenues, partially offset by an increase in fee-based terminal revenues.  The decrease in delivery revenues was primarily due to lower average tariffs, due both to lower rates on the system’s East Line deliveries as a result of rate case settlements since the end of the third quarter of 2010 and to lower military tenders.  The increase in terminal revenues was largely attributable to a 12% increase in ethanol handling volumes;

 

▪

decreases of $0.6 million (4%) and $3.8 million (9%), respectively, from our Calnev Pipeline.  Earnings from Calnev were essentially unchanged across the comparable three month periods, but decreased across the comparable nine month periods due largely to a 21% drop in ethanol handling volumes in the first nine months of 2011, due both to lower deliveries to the Las Vegas market, and to incremental ethanol blending services offered by a competing terminal.

 

table of content

54

---

 

Natural Gas Pipelines

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions, except operating statistics)
Revenues(a)		$	1,176.4			$	1,147.6			$	3,240.1			$	3,414.0
Operating expenses(b)			(981.8	)			(1,001.8	)			(2,744.9	)			(2,938.1	)
Earnings from equity investments			50.8				42.0				154.6				115.9
Interest income and Other, net(c)			(164.1	)			0.6				(161.7	)			2.9
Income tax expense			(0.5	)			(1.1	)			(3.4	)			(1.8	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	80.8			$	187.3			$	484.7			$	592.9
Natural gas transport volumes (Bcf)(d)			738.5				658.6				2,167.5				1,925.6
Natural gas sales volumes (Bcf)(e)			215.1				214.1				598.7				602.1

____________

 

(a)	Nine month 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)	Nine month 2011 amount includes a $9.7 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  Three and nine month 2010 amounts include unrealized losses of $1.6 million and $0.8 million, respectively, on derivative contracts used to hedge forecasted natural gas sales.
(c)	Three and nine month 2011 amounts include a $167.2 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk Field Services LLC to fair value.
(d)	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.
(e)	Represents Texas intrastate natural gas pipeline group volumes.

Combined, the certain items described in the footnotes to the table above accounted for (i) a $165.6 million decrease in segment earnings before depreciation, depletion and amortization expenses in the third quarter of 2011; (ii) a $176.5 million decrease in earnings before depreciation, depletion and amortization in the first nine months of 2011; and (iii) a $0.4 million decrease in revenues in the first nine months of 2011, when compared to the same periods of 2010.  Following is information, for each of the comparable three and nine month periods of 2011 and 2010, related to the segment’s (i) remaining $59.1 million (31%) and $68.3 million (12%) increases in earnings before depreciation, depletion and amortization; and (ii) $28.8 million (3%) increase and remaining $173.5 million (5%) decrease in operating revenues:

 

Three Months Ended September 30, 2011 versus Three Months Ended September 30, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
KinderHawk Field Services(a)		$	40.2				n/a			$	49.3				n/a
Texas Intrastate Natural Gas Pipeline Group			6.7				10	%			(15.5	)			(2	)%
Fayetteville Express Pipeline(b)			6.1				n/a				n/a				n/a
Kinder Morgan Interstate Gas Transmission			3.1				13	%			(6.9	)			(13	)%
Midcontinent Express Pipeline(b)			2.8				35	%			n/a				n/a
Casper and Douglas Natural Gas Processing			1.7				40	%			5.3				23	%
Rockies Express Pipeline(b)			0.6				3	%			n/a				n/a
Trailblazer Pipeline			(2.0	)			(19	)%			(1.8	)			(13	)%
All others (including eliminations)			(0.1	)			-				(1.6	)			(3	)%
Total Natural Gas Pipelines		$	59.1				31	%		$	28.8				3	%

____________

Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
KinderHawk Field Services(a)		$	60.8				n/a			$	49.3				n/a
Fayetteville Express Pipeline(b)			11.7				n/a				n/a				n/a
Midcontinent Express Pipeline(b)			10.3				49	%			n/a				n/a
Casper and Douglas Natural Gas Processing			8.9				67	%			18.8				25	%
Texas Intrastate Natural Gas Pipeline Group			5.9				3	%			(214.9	)			(7	)%
Kinder Morgan Interstate Gas Transmission			(12.6	)			(16	)%			(20.1	)			(15	)%
Trailblazer Pipeline			(8.0	)			(24	)%			(3.2	)			(8	)%
Rockies Express Pipeline(b)			(5.7	)			(9	)%			n/a				n/a
All others (including eliminations)			(3.0	)			(2	)%			(3.4	)			(2	)%
Total Natural Gas Pipelines		$	68.3				12	%		$	(173.5	)			(5	)%

 

table of content

55

---

 

 

(a)	Equity investment until July 1, 2011.  See Note (b).
(b)	Equity investment.  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 primary increases and decreases in our Natural Gas Pipelines business segment’s earnings before depreciation, depletion and amortization expenses in the comparable three and nine month periods of 2011 and 2010 included the following:

 

▪

increases of $40.2 million and $60.8 million, respectively, from incremental earnings from our now wholly-owned KinderHawk Field Services LLC.  We acquired an initial 50% ownership interest in KinderHawk on May 21, 2010 and we accounted for this investment under the equity method of accounting.  On July 1, 2011, we acquired the remaining 50% ownership interest in KinderHawk and we now account for our investment under the full consolidation method.  For more information about our July 2011 KinderHawk acquisition, see Note 2 “Acquisitions and Divestitures—Acquisitions— KinderHawk Field Services LLC and EagleHawk Field Services LLC” to our consolidated financial statements included elsewhere in this report;

 

▪

increases of $6.7 million (10%) and $5.9 million (3%), respectively, from our Texas intrastate natural gas pipeline group.  The increase in earnings for the comparable third quarter periods was due to (i) higher earnings from natural gas processing activities (due largely to higher average natural gas liquids prices); (ii) a favorable settlement related to the natural gas drilling and gathering operations of GMX, the original owner and now remaining 60% owner of our 40%-owned Endeavor Gathering LLC; and (iii) higher natural gas transportation margins (due largely to an 18% increase in delivery volumes).  The overall increase was partially offset, however, by lower margins from natural gas sales, mainly attributable to higher costs of natural gas supplies relative to sales price.  For the comparable nine month periods, the increase in earnings was primarily due to (i) higher margins from both natural gas storage and transportation services (due to favorable storage price spreads and a 12% increase in transportation volumes); (ii) higher earnings from natural gas processing activities; and (iii) incremental equity earnings from both Endeavor and our 50%-owned Eagle Ford Gathering LLC.  The overall increase was partially offset by lower natural gas sales margins and higher pipeline integrity expenses;

 

▪

increases of $6.1 million and $11.7 million, respectively, from incremental equity earnings from our 50% interest in the Fayetteville Express pipeline system.  The Fayetteville Express system began firm contract transportation service on January 1, 2011;

 

▪

an increase of $3.1 million (13%) and a decrease of $12.6 million (16%), respectively, from our Kinder Morgan Interstate Gas Transmission pipeline system.  The increase in earnings for the comparable three month periods was driven by higher margins on operational gas sales in the third quarter of 2011.  The decrease in earnings for the comparable nine month periods was driven by lower net fuel recoveries and lower transportation revenues, due both to a 14 % drop in transportation volumes and to the regulatory settlement discussed in Note 10 “Litigation, Environmental and Other Contingencies—Federal Energy Regulatory Commission Proceedings— Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding” to our consolidated financial statements included elsewhere in this report;

 

▪

increases of $2.8 million (35%) and $10.3 million (49%), respectively, from our 50% interest in the Midcontinent Express pipeline system.  The increases were driven by higher transportation revenues, and for the comparable nine month periods, by the June 2010 completion of an expansion project 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;

 

▪

increases of $1.7 million (40%) and $8.9 million (67%), respectively, from our Casper Douglas gas processing operations, primarily attributable to both higher processing spreads and higher sales volumes.  The increases in sales volumes were due largely to increased drilling activity in the Douglas, Wyoming plant area;

 

table of content

56

---

 

 

▪

an increase of $0.6 million (3%) and a decrease of $5.7 million (9%), respectively, in equity earnings from our 50% ownership interest in the Rockies Express pipeline system.  For the comparable nine month periods, equity earnings decreased due primarily to higher interest expenses and higher operating expenses .  Rockies Express issued $1.7 billion aggregate principal amount of fixed rate senior notes in a private offering in March 2010 to secure permanent financing for the Rockies Express pipeline construction costs.  The increase in operating expenses was due in part to the write-off of certain transportation fuel recovery receivables pursuant to a contractual agreement.  The overall decrease in net income was partially offset by higher firm reservation fees in the first nine months of 2011, due in part to a portion of the Rockies Express-East pipeline segment being shutdown for 26 days in the first quarter of 2010 due to a pipeline girth weld failure that occurred in November 2009; and

 

▪

decreases of $2.0 million (19%) and $8.0 million (24%), respectively, from our Trailblazer pipeline system, mainly attributable to lower transportation base rates (as a result of rate case settlements since the end of the third quarter of 2010), lower backhaul transportation services, and for the comparable nine month periods, a $4.3 million increase in expense from the write-off of receivables for under-collected fuel (incremental to the $9.7 million increase in expense that is described in footnote (b) to the results of operations table above and which relates to periods prior to 2011).

 

The overall changes in both segment revenues and segment operating expenses (which include natural gas costs of sales) in the comparable three and nine 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.  For the comparable third quarter periods of 2011 and 2010, our Texas intrastate natural gas pipeline group accounted for 85% and 88%, respectively, of the segment’s revenues, and 94% and 94%, respectively, of the segment’s operating expenses.  For the comparable nine month periods of both years, the intrastate group accounted for 87% and 89%, respectively, of total revenues, and 94% and 95%, respectively, of total segment operating expenses.

 

 

 

 

 

 

 

 

 

table of content

57

---

 

 

CO 2

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions, except operating statistics)
Revenues(a)		$	372.0			$	296.0			$	1,062.8			$	932.4
Operating expenses			(83.1	)			(78.2	)			(256.0	)			(229.9	)
Earnings from equity investments			6.1				4.7				17.7				17.7
Interest income and Other, net			1.0				-				2.1				1.9
Income tax (expense) benefit			(1.2	)			(1.0	)			(3.4	)			2.0
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	294.8			$	221.5			$	823.2			$	724.1
Southwest Colorado carbon dioxide production (gross) (Bcf/d)(b)			1.2				1.2				1.2				1.2
Southwest Colorado carbon dioxide production (net) (Bcf/d)(b)			0.5				0.5				0.5				0.5
SACROC oil production (gross)(MBbl/d)(c)			29.4				29.0				28.9				29.4
SACROC oil production (net)(MBbl/d)(d)			24.5				24.2				24.1				24.5
Yates oil production (gross)(MBbl/d)(c)			21.5				23.2				21.7				24.4
Yates oil production (net)(MBbl/d)(d)			9.5				10.3				9.6				10.8
Katz oil production (gross)(MBbl/d)(c)			0.5				0.3				0.3				0.3
Katz oil production (net)(MBbl/d)(d)			0.4				0.2				0.3				0.3
Natural gas liquids sales volumes (net)(MBbl/d)(d)			8.4				10.0				8.4				9.9
Realized weighted average oil price per Bbl(e)		$	70.43			$	59.54			$	69.54			$	59.88
Realized weighted average natural gas liquids price per Bbl(f)		$	68.86			$	46.73			$	65.53			$	50.06

____________

(a)	Three and nine month 2011 amounts include unrealized gains of $8.5 million and $10.4 million, respectively, and three and nine month 2010 amounts include unrealized losses of $7.9 million and unrealized gains of $5.4 million, respectively, all relating to 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)	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 three and nine months ended September 30, 2011, the unrealized gains and losses on derivative contracts used to hedge forecasted crude oil sales and described in footnote (a) to the table above increased both earnings before depreciation, depletion and amortization and revenues by $16.4 million and $5.0 million, respectively, when compared to the same periods of 2010.  For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three and nine month periods of 2011 and 2010, in the segment’s remaining (i) $56.9 million (25%) and $94.1 million (13%) increases in earnings before depreciation, depletion and amortization; and (ii) $59.6 million (20%) and $125.4 million (14%) increases in operating revenues:

 

 

 

 

table of content

58

---

 

Three Months Ended September 30, 2011 versus Three Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Oil and Gas Producing Activities		$	46.0				28	%		$	47.8				20	%
Sales and Transportation Activities			10.9				18	%			15.7				22	%
Intrasegment eliminations			-				-				(3.9	)			(30	)%
Total CO 2		$	56.9				25	%		$	59.6				20	%

____________

 

Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Oil and Gas Producing Activities		$	66.0				13	%		$	91.0				12	%
Sales and Transportation Activities			28.1				14	%			46.8				21	%
Intrasegment eliminations			-				-				(12.4	)			(32	)%
Total CO 2		$	94.1				13	%		$	125.4				14	%

The segment’s oil and gas producing activities include the operations associated with its ownership interests in oil-producing fields and natural gas processing plants, and generally, earnings from these activities are closely aligned with realized price levels for crude oil and natural gas liquids products.  When compared to the same two periods of 2010, the increases in earnings in the three and nine month periods ended September 30, 2011 were mainly due to the following:

 

▪

increases of $33.2 million (17%) and $65.0 million (11%), respectively, in crude oil sales revenues—due to higher average realized sales prices for U.S. crude oil.  Our realized weighted average price per barrel of crude oil increased 18% in the third quarter of 2011 and 16% in the first nine months of 2011, when compared to the same periods in 2010. The overall increases in crude oil sales revenues were partially offset by small decreases in oil production volumes at the SACROC and Yates field units (volumes presented in the results of operations table above);

 

▪

increases of $10.1 million (23%) and $13.9 million (10%), respectively, in natural gas plant products sales revenues, due to increases of 47% and 31%, respectively, in our realized weighted average price per barrel of natural gas liquids.  The increases in revenues from higher realized sales prices were partially offset by decreases in liquids sales volumes of 16% and 15%, respectively.  The decreases in volumes were mainly related to the contractual reduction in our net interest in liquids production from the SACROC field (described following);

 

▪

increases of $4.6 million (118%) and $13.2 million (119%), respectively, in net profits interest revenues from our 28% net profits interest in the Snyder, Texas natural gas processing plant.  The increases in net profits interest revenues from the Snyder plant were driven by higher natural gas liquids prices in the first nine months of 2011, record producing volumes in the third quarter of 2011, and the favorable impact from the restructuring of certain liquids processing contracts that became effective at the beginning of 2011; and

 

▪

decreases of $2.7 million (3%) and $23.9 million (10%), respectively, due to higher combined operating expenses, driven primarily by higher carbon dioxide supply expenses that related to both initiating carbon dioxide injections into the Katz field and higher carbon dioxide prices.  The overall increases in expense were partially offset by a $14.0 million reduction in severance tax expense recognized in the third quarter of 2011.

 

The overall period-to-period increases in earnings from the segment’s sales and transportation activities were mainly due to the following:

 

▪

increases of $13.9 million (27%) and $37.4 million (24%), respectively, in carbon dioxide sales revenues, primarily due to higher average sales prices.  The segment’s average price received for all carbon dioxide sales in the third quarter and first nine months of 2011 increased 23% and 22%, respectively, due largely to the fact that a portion of its carbon dioxide sales contracts are indexed to oil prices.  Overall carbon dioxide sales volumes increased by 3% in the third quarter of 2011 and by 2% in the first nine months of 2011, versus the same prior year periods;

 

▪

increases of $1.9 million (10%) and $5.6 million (10%), respectively, in carbon dioxide and crude oil pipeline transportation revenues, due mainly to incremental transportation service on our Eastern Shelf carbon dioxide pipeline.  We completed construction of the pipeline in December 2010;

 

▪

decreases of $6.3 million (45%) and $14.6 million (35%), respectively, due to higher combined operating expenses.  The increases were driven by higher severance tax expenses and higher carbon dioxide supply expenses, both related to higher commodity prices in the first nine months of 2011;

 

▪

for the comparable nine month periods, an increase of $3.8 million (75%) in other revenues, due mainly to incremental earnings from third-party reimbursement and construction agreements; and

 

▪

for the comparable nine month periods, a $5.3 million (271%) decrease due to higher income tax expenses, resulting primarily from decreases in tax expense in the first nine months of 2010 due to the expensing of previously capitalized carbon dioxide costs.

 

table of content

59

---

 

 

Terminals

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions, except operating statistics)
Revenues		$	328.1			$	321.5			$	980.3			$	946.1
Operating expenses(a)			(155.5	)			(163.7	)			(479.6	)			(480.3	)
Other income (expense)(b)			1.1				(0.1	)			4.5				10.4
Earnings from equity investments			2.9				0.7				7.8				1.3
Interest income and Other, net(c)			0.4				2.8				4.9				3.2
Income tax benefit (expense)(d)			2.8				(2.0	)			6.6				(5.5	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	179.8			$	159.2			$	524.5			$	475.2
Bulk transload tonnage (MMtons)(e)			26.6				24.1				75.5				71.4
Ethanol (MMBbl)			15.5				14.1				44.9				44.2
Liquids leaseable capacity (MMBbl)			59.5				58.2				59.5				58.2
Liquids utilization %			93.2	%			96.2	%			93.2	%			96.2	%

__________

(a)	Three and nine month 2011 amounts include (i) increases in expense of $1.2 million and $2.8 million, respectively, from casualty insurance deductibles and the repair of assets related to casualty losses; (ii) increases in expense of $0.1 million and $0.7 million, respectively, 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) increases in expense of $0.1 million associated with the dissolution of our partnership interest in Globalplex Handling.  Nine month 2011 amount also includes a $1.2 million increase in expense associated with environmental liability adjustments, and a $0.6 million increase in expense associated with the settlement of a litigation matter at our Carteret, New Jersey liquids terminal.  Three and nine month 2010 amounts include a $5.0 million increase in expense from casualty insurance deductibles, and a $0.2 million decrease in expense from certain measurement period adjustments related to our March 5, 2010 Slay Industries terminal acquisition.  Nine month 2010 amount also includes a $0.6 million increase in expense related to storm and flood clean-up and repair activities.
(b)	Three and nine month 2011 amounts include (i) a $1.3 million increase in income from the sale of our ownership interest in Arrow Terminals B.V.; (ii) a $0.4 million decrease in income from property write-offs associated with the dissolution of our partnership interest in Globalplex Handling; and (iii) a $0.1 million decrease in income and a $0.8 million increase in income, respectively, 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.  Nine month 2011 amount also includes a $4.3 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal, and a $1.6 million decrease in income from the write-off of assets related to casualty losses.  Nine month 2010 amount includes a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal.
(c)	Nine month 2011 amount includes a combined $3.6 million gain from the sale of a 51% ownership interest in two of our subsidiaries: River Consulting LLC and Devco USA L.L.C.
(d)	Nine month 2011 amount includes (i) a $4.7 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 or realize any direct benefits related to this expense); (ii) 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 consolidated financial statements in our 2010 Form 10-K/A; and (iii) a $1.4 million increase in expense related to the gain associated with the sale of a 51% ownership interest in two of our subsidiaries described in footnote (c).
(e)	Volumes for acquired terminals are included for all periods.

 

table of content

60

---

 

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.

 

Combined, the certain items described in the footnotes to the table above accounted for a $4.2 million increase in segment earnings before depreciation, depletion and amortization expenses in the third quarter of 2011, and a   $6.5 million increase in earnings before depreciation, depletion and amortization in the first nine months of 2011, when compared to the same two periods of 2010.

 

In addition, in both 2011 and 2010, we acquired certain terminal assets and businesses, and combined, these acquired operations contributed incremental earnings before depreciation, depletion and amortization of $3.9 million, equity earnings of $1.9 million and revenues of $2.8 million in the third quarter of 2011, and contributed incremental earnings before depreciation, depletion and amortization of $11.5 million, equity earnings of $5.7 million and revenues of $9.5 million in the first nine months of 2011.   All of the incremental amounts from our acquisitions represent the earnings and revenues from acquired terminals’ operations during the additional months of ownership in 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 nine months of 2011, see Note 2 “Acquisitions 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.

 

Following is information, for the comparable three and nine month periods of 2011 and 2010, related to the remaining increases and decreases in the segment’s (i) earnings before depreciation, depletion and amortization expenses; and (ii) operating revenues.  The 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 September 30, 2011 versus Three Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Mid-Atlantic		$	5.1				63	%		$	9.6				48	%
Northeast			4.2				23	%			2.6				8	%
Gulf Bulk			3.5				19	%			3.3				10	%
Gulf Liquids			(2.6	)			(6	)%			1.4				3	%
Southeast			(0.2	)			(1	)%			(0.3	)			(1	)%
All others (including intrasegment eliminations and unallocated income tax expenses)			2.5				4	%			(12.8	)			(8	)%
Total Terminals		$	12.5				8	%		$	3.8				1	%

__________

table of content

61

---

 

 

Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Mid-Atlantic		$	13.5				46	%		$	19.7				28	%
Gulf Liquids			10.4				9	%			18.6				12	%
Northeast			4.3				7	%			8.2				8	%
Southeast			3.5				10	%			2.1				3	%
Gulf Bulk			(1.4	)			(3	)%			3.4				3	%
All others (including intrasegment eliminations and unallocated income tax expenses)			1.0				1	%			(27.3	)			(6	)%
Total Terminals		$	31.3				7	%		$	24.7				3	%

The increases in earnings from the terminals included in our Mid-Atlantic region were driven by increases in earnings of $3.1 million and $12.8 million, respectively, from our terminal located in Newport News, Virginia.  The earnings increases were driven by increases in coal transload volumes, consistent with the ongoing domestic economic recovery, growth in the export market due to greater foreign demand for both U.S. metallurgical and steam coal, and completed terminal expansions since the end of the third quarter of 2010.  Including all terminals, coal volumes handled increased by 23% in the third quarter of 2011, versus the third quarter last year. The overall quarter-to-quarter increase in earnings also included a $2.1 million increase from our Chesapeake Bay, Maryland bulk terminal, due to higher revenues from increased iron, steel slag, and petroleum coke volumes.

 

The increases in earnings from our Northeast terminals were driven by strong third quarter 2011 results from our three New York Harbor liquids terminals.  The increase was driven by completed liquids tank expansion projects since the end of the third quarter of 2010, higher transfer and storage rates, and a decrease in operating expenses that related primarily to lower dredging expenses.

 

Earnings from our Gulf Bulk terminals increased by $3.5 million (19%) in the third quarter of 2011, but decreased by $1.4 million (3%) in the first nine months of 2011, when compared to the same prior year periods.  The quarter-to-quarter increase was driven by higher petroleum coke volumes from our petroleum coke operations in the third quarter of 2011.  For the comparable nine month periods, the decrease in earnings was chiefly due to a drop in petroleum coke volumes, caused partly by refinery turnarounds in the first half of 2011, and partly to certain contract terminations.

 

Earnings from our Gulf Liquids terminals decreased by $2.6 million (6%) in the third quarter of 2011, but increased by $10.4 million (9%) in the first nine months of 2011, when compared to the same periods last year.  The quarter-to-quarter decrease in earnings was primarily due to a favorable customer settlement in July 2010.  For the comparable nine month periods, the increase was driven by new and renewed customer agreements at higher rates, and to the completion of terminal expansion projects since the end of the third quarter of 2010.  Including all terminals, we increased our liquids terminals’ leasable capacity by 1.3 million barrels (2.2%) since the end of the third quarter last year, via both terminal acquisitions and completed terminal expansion projects.

 

Earnings from our Southeast terminals were essentially flat across both third quarter periods, but increased $3.5 million (10%) across the comparable nine month periods.  The increases in earnings were driven by higher chemical revenues, increased salt handling, and higher storage fees.  We also benefitted from both higher volumes and margins from tank blending services involving various agricultural products, and to a favorable claim settlement in the second quarter of 2011.

 

The remaining increases and decreases in our Terminals segment’s earnings and revenues—reported in the “All others” line in the two tables above—relate largely to terminal assets we sold (or contributed to joint ventures) and no longer consolidate since the end of the third quarter of 2010.

 

 

 

 

table of content

62

---

 

 

Kinder Morgan Canada

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions, except operating statistics)
Revenues		$	77.4			$	67.5			$	230.3			$	197.9
Operating expenses			(26.4	)			(23.6	)			(76.8	)			(66.8	)
Earnings (losses) from equity investments			0.2				(1.3	)			(1.6	)			(1.5	)
Interest income and Other, net			3.6				4.7				10.3				12.3
Income tax expense(a)			(6.3	)			(3.3	)			(12.2	)			(9.0	)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments		$	48.5			$	44.0			$	150.0			$	132.9
Transport volumes (MMBbl)(b)			25.6				27.2				75.2				79.3

__________

(a)	Nine month 2011 amount includes a $2.2 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 or realize any direct benefits related to this expense).
(b)	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.  The certain item relating to income tax savings described in footnote (a) to the table above increased earnings before depreciation, depletion and amortization by $2.2 million in the first nine months of 2011, when compared to the first nine months of 2010.  For each of the segment’s three primary businesses, following is information for each of the comparable three and nine month periods of 2011 and 2010, related to the segment’s (i) $4.5 million (10%) and remaining $14.9 million (11%) increases in earnings before depreciation, depletion and amortization; and (ii) $9.9 million (15%) and $32.4 million (16%) increases in operating revenues:

 

Three Months Ended September 30, 2011 versus Three Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Trans Mountain Pipeline		$	3.5				9	%		$	9.8				15	%
Jet Fuel Pipeline			(0.1	)			(9	)%			0.1				6	%
Express Pipeline(a)			1.1				54	%			n/a				n/a
Total Kinder Morgan Canada		$	4.5				10	%		$	9.9				15	%

__________

Nine Months Ended September 30, 2011 versus Nine Months Ended September 30, 2010

 

		EBDA increase/(decrease)								Revenues increase/(decrease)
		(In millions, except percentages)
Trans Mountain Pipeline		$	14.7				12	%		$	32.1				17	%
Jet Fuel Pipeline			0.3				10	%			0.3				6	%
Express Pipeline(a)			(0.1	)			(1	)%			n/a				n/a
Total Kinder Morgan Canada		$	14.9				11	%		$	32.4				16	%

(a)	Equity investment.  We record earnings under the equity method of accounting.

The overall increases in Trans Mountain’s earnings before depreciation, depletion and amortization expenses included increases of $1.4 million and $5.0 million, respectively, due to favorable currency impacts.  Trans Mountain’s remaining $2.1 million and $9.7 million period-to-period increases in earnings before depreciation, depletion and amortization were driven by higher operating revenues, primarily due to favorable impacts from a negotiated pipeline toll settlement agreement which became effective on January 1, 2011.  The one-year negotiated toll agreement was formally approved by the National Energy Board (Canada) on April 29, 2011, and replaced the previous mainline toll settlement agreement that expired on December 31, 2010.

 

The increase in earnings from our investment in the Express pipeline system for the comparable three month periods related to higher net income earned by Express in the third quarter of 2011, primarily due to increased domestic volume on the Express’ Platte Pipeline segment.

 

table of content

63

---

 

Other

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(In millions)
General and administrative expenses(a)		$	100.5			$	93.6			$	387.1			$	288.1
Interest expense, net of unallocable interest income(b)		$	132.5			$	133.8			$	393.8			$	373.9
Unallocable income tax expense		$	2.1			$	4.2			$	6.8			$	8.4
Net income attributable to noncontrolling interests(c)		$	1.8			$	1.6			$	6.3			$	7.6

__________

(a)	Three and nine month 2011 amounts include (i) increases in expense of $0.3 million for certain legal expenses associated with business acquisitions; (ii) increases in expense of $0.1 million and $1.2 million, respectively, for certain asset and business acquisition costs; (iii) a $0.2 million decrease in unallocated payroll tax expense and a $1.2 million increase in unallocated payroll tax expense, respectively, all related to the $87.1 million special non-cash bonus expense to non-senior management employees allocated to us from KMI in the first quarter of 2011 (however, we do not have any obligation, nor do we expect to pay any amounts related to this expense); and (iv) decreases in expense of $0.1 million and $0.2 million, respectively, related to capitalized overhead costs associated with the 2008 hurricane season.  Nine month 2011 amount also includes a combined $89.9 million increase in non-cash compensation expense (including $87.1 million related to a special non-cash bonus expense to non-senior management employees), allocated to us from KMI; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense.  Three and nine month 2010 amounts include (i) increases in expense of $1.0 million and $3.7 million, respectively, from 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 these expenses); and (ii) increases in expense of $1.1 million and $3.5 million, respectively, for certain asset and business acquisition costs.  Nine month 2010 amount also includes a $1.6 million increase in legal expense associated with certain items such as legal settlements and pipeline failures, and a $0.2 million decrease in expense related to capitalized overhead costs associated with the 2008 hurricane season.
(b)	Three and nine month 2011 amounts include increases in imputed interest expense of $0.1 million and $0.5 million, respectively, and three and nine month 2010 amounts include increases in imputed interest expense of $0.2 million and $0.8 million, respectively, all related to our January 1, 2007 Cochin Pipeline acquisition.
(c)	Three and nine month 2011 amounts include decreases of $3.0 million and $6.5 million, respectively, in net income attributable to our noncontrolling interests, and the three and nine month 2010 amounts include decreases of $1.9 million and $4.3 million, respectively, in net income attributable to our noncontrolling interests, all related to the combined effect of the three and nine month 2011 and 2010 items previously disclosed in the footnotes to the tables included above in “—Results of Operations.”

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.

 

Combined, the certain items described in footnote (a) to the table above decreased our general and administrative expenses by $2.0 million in the third quarter of 2011 and increased our general and administrative expenses by $83.8 million in the first nine months of 2011, when compared to the same two periods of 2010.  The remaining $8.9 million (10%) and $15.2 million (5%) period-to-period increases in expenses were driven by (i) higher employee benefit and payroll tax expenses, due mainly to both cost inflation increases on work-based health and insurance benefits and higher wage rates; and (ii) higher unallocated expenses related to our Canadian pipeline operations, including higher environmental, rent, and pension expenses.

 

table of content

64

---

 

In the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our interest expense to arrive at one interest amount.  After taking into effect the certain items described in footnote (b) to the table above, our total interest expense was essentially flat across both third quarter periods, but increased by $20.2 million (5%) in the first nine months of 2011, when compared with the same nine month period last year.  The year-over-year increase in interest expense was due to a higher average debt balance in 2011 (average borrowings for nine month period ended September 30, 2011 increased 7.9%, when compared to the same period a year ago), largely due to the capital expenditures, business acquisitions, and joint venture contributions we have made since the end of the third quarter of 2010.  The weighted average interest rate on all of our borrowings—including both short-term and long-term amounts—in the first nine months of 2011 was essentially flat versus the average rate during 2010 (from 4.34% for the first nine months of 2010 to 4.28% for the first nine months of 2011).

 

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 as of September 30, 2011, approximately 46% of our $12,506.6 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 September 30, 2011, we had $271.0 million of “Cash and cash equivalents” on our consolidated balance sheet (included elsewhere in this report), an increase of $141.9 million from December 31, 2010.  We also had, as of September 30, 2011, approximately $1.6 billion of borrowing capacity available under our $2.2 billion senior unsecured revolving 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 (including commercial paper issuances), 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.”

 

 

table of content

65

---

 

 

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 (negative) and BBB (stable), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch Inc., respectively.  On October 18, 2011, Moody’s revised its outlook on our long-term credit rating to negative from stable.  The rating agency’s revision reflected its expectation that our financial profile may deteriorate due to higher debt obligations associated with KMI’s announcement that it has reached an agreement to purchase 100% of the outstanding stock of El Paso Corporation.  Further information about this announcement is described in Note 1 “General—Kinder Morgan, Inc., Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc.—Subsequent Event” to our consolidated financial statements included elsewhere in this report.

 

Our short-term corporate debt credit rating is A-2 (susceptible to adverse economic conditions, however, capacity to meet financial commitments is satisfactory), Prime-2 (strong ability to repay short-term debt obligations) and F2 (good quality grade with satisfactory capacity to meet financial commitments), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch Inc., respectively.  Based on these credit ratings, 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 have no material concentrations of credit risk and we believe we have provided adequate allowance for such customers.

 

Short-term Liquidity

 

As of September 30, 2011, our principal sources of short-term liquidity were (i) our $2.2 billion five-year senior unsecured revolving credit facility with a diverse syndicate of banks that matures July 1, 2016; (ii) our $2.2 billion short-term commercial paper program (which is supported by our revolving credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings and letters of credit); and (iii) cash from operations.  The loan commitments under our revolving credit facility can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper program.  The facility can be amended to allow for borrowings of up to $2.5 billion.

 

As of September 30, 2011, our credit facility was not drawn on, and as discussed above in “—General,” we provide for additional liquidity by maintaining a sizable amount of excess borrowing capacity related to our credit facility.  After reduction for (i) borrowings under our commercial paper program; and (ii) our outstanding letters of credit, the remaining available borrowing capacity under our credit facility was $1,615.2 million as of September 30, 2011.

 

Additionally, we have consistently generated strong cash flow from operations.  In the first nine months of 2011 and 2010, we generated $1,975.1 million and $1,527.3 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 September 30, 2011 was $1,844.4 million, primarily consisting of (i) $353.0 million of commercial paper borrowings; (ii) $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 holders on February 1, 2012 pursuant to certain repurchase provisions contained in the bond indenture; (iii) $450.0 million in principal amount of 7.125% senior notes that mature March 15, 2012; and (iv) $500.0 million in principal amount of 5.85% senior notes that mature September 15, 2012.  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 credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt.

 

table of content

66

---

 

We had working capital deficits of $1,664.3 million as of September 30, 2011 and $1,477.5 million as of December 31, 2010.  The $186.8 million (13%) unfavorable change from year-end 2010 was primarily due to a $582.0 million increase in short-term debt, partially offset by a $320.8 million increase in working capital attributable to the change in fair value of short-term derivative contracts.  The overall increase in short-term debt was mainly due to the following (i) a $1,450.0 million increase due to the reclassification of the principal amount of three separate series of senior notes (described above) from long-term to short-term debt; (ii) a $700.0 million decrease due to the repayment of $700 million in principal amount of senior notes that matured in March 2011; and (iii) a $169.1 million decrease due to net repayments of commercial paper borrowings.

 

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.  Although working capital can be considered a measure of a company’s ability to meet its short-term cash needs, a working capital deficit is not unusual for us or for other companies similar in size and scope to us.  Furthermore, 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.  

 

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 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 nine months of 2011, including our issuances of senior notes, see Note 4 “Debt” to our consolidated financial statements included elsewhere in this report.

 

As of September 30, 2011 and December 31, 2010, the net carrying value of the various series of our senior notes was $12,025.3 million and $10,876.7 million, respectively, and the total liability balance due on the various borrowings of our operating partnerships and subsidiaries was $128.3 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.

 

table of content

67

---

 

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 nine months of 2011, our sustaining capital expenditures totaled $140.2 million.  This amount included $3.5 million for our proportionate share of the sustaining capital expenditures of (i) Rockies Express Pipeline LLC; (ii) Midcontinent Express Pipeline LLC; (iii) Fayetteville Express Pipeline LLC; (iv) Cypress Interstate Pipeline LLC; (v) EagleHawk Field Services LLC; and (vi) for the first six months of 2011 only, KinderHawk Field Services LLC (effective July 1, 2011, we acquired the remaining 50% ownership interest in KinderHawk that we did not already own and we subsequently included its sustaining capital expenditures in our consolidated totals).

 

For the first nine months of 2010, our sustaining capital expenditures totaled $120.9 million (including $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 three months of 2011 for sustaining capital expenditures are approximately $72.6 million, including our proportionate shares of Rockies Express, Midcontinent Express, Fayetteville Express and Cypress.

 

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, Rockies Express, Midcontinent Express and Fayetteville Express can each fund their own cash requirements for expansion capital expenditures through borrowings under their own credit facilities or with proceeds from contributions received from their member owners.  Both Rockies Express and Midcontinent Express can also generate funds by issuing their own long-term notes.  We have no contingent debt obligations with respect to Rockies Express, Midcontinent Express, Fayetteville Express, or Cypress.  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 totaled $701.0 million in the first nine months of 2011 and $601.3 million in the first nine months of 2010.  The period-to-period increase in discretionary capital expenditures was primarily due to higher investment undertaken in the first nine months of 2011 to expand and improve our CO 2 and Products Pipelines business segments.  Generally, we initially fund our discretionary capital expenditures through borrowings under our revolving 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 September 30, 2011, our current forecast for discretionary capital expenditures for 2011 is approximately $1.0 billion.  This amount does not include forecasted discretionary expenditures by our equity investees, forecasted capital contributions to our equity investees, or forecasted expenditures for asset acquisitions.

 

Operating Activities

 

Net cash provided by operating activities was $1,975.1 million for the nine months ended September 30, 2011, versus $1,527.3 million in the same comparable period of 2010.  The period-to-period increase of $447.8 million (29%) in cash flow from operations consisted of the following:

 

table of content

68

---

 

 

▪

a $183.7 million increase in cash from overall higher partnership income—after adjusting our period-to-period $125.8 million decrease in net income for the following five non-cash items: (i) a $167.2 million increase relating to the non-cash loss from the remeasurement of our previous 50% equity interest in KinderHawk Field Services LLC (as discussed in Note 2 “Acquisitions and Divestitures” to our consolidated financial statements included elsewhere in this report); (ii) an $86.2 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); (iii) an $83.8 million increase in expense from adjustments made to our rate case and other legal liabilities; (iv) a $30.6 million increase due to higher non-cash depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments); and (v) a $58.3 million decrease due to higher earnings from equity investees.  The period-to-period change 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 $124.9 million increase in cash attributable to lower payments made in 2011 to various shippers on our Pacific operations’ refined products pipelines.  In the first nine months of 2011 and 2010, we paid legal settlements of $81.4 million and $206.3 million, respectively, to settle various interstate and California intrastate transportation rate challenges filed by shippers with the FERC and the CPUC, respectively, dating back as early as 1992;

 

▪

a $79.8 million increase in cash related to net changes in both non-current assets and liabilities and other non-cash income and expense items, primarily driven by (i) a $124.2 million increase in cash due to higher net dock premiums and toll collections received from our Trans Mountain pipeline system customers; and (ii) a net $39.2 million decrease in cash attributable to lower non-cash earnings adjustments in the first nine months of 2011, including, among other items, income from the sale or casualty of net assets, amortization of debt-related discounts and premiums, and deferred tax expenses;

 

▪

a $73.0 million increase in cash from interest rate swap termination payments received in August 2011, when we terminated two separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $200.0 million;

 

▪

a $46.0 million increase in cash from higher distributions of earnings from equity investees.  The increase was chiefly due to incremental distributions of (i) $15.3 million received from KinderHawk Field Services LLC (for the periods prior to our July 1, 2011 acquisition of the remaining 50% interest in KinderHawk that we did not already own); (ii) $11.6 million received from our 50%-owned Fayetteville Express Pipeline LLC; and (iii) $10.3 million received from our 50%-owned Midcontinent Express Pipeline LLC; and

 

▪

a $59.6 million decrease in cash relative to net changes in working capital items, primarily due to a $55.6 million decrease 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.

 

Investing Activities

 

Net cash used in investing activities was $1,826.7 million for the nine month period ended September 30, 2011, compared to $1,908.3 million in the comparable 2010 period.  The $81.6 million (4%) increase in cash in the first nine months of 2011 due to lower cash expended for investing activities was primarily attributable to:

 

▪

a $227.8 million increase in cash due to lower acquisitions of assets and investments.  In the first nine months of 2011, we paid $945.0 million for strategic acquisitions, including (i) $835.1 million for both our remaining 50% ownership interest in KinderHawk Field Services LLC and our 25% interest in EagleHawk Field Services LLC; (ii) $50.0 million for our preferred equity interest in Watco Companies, LLC; and (iii) $42.9 million for terminal assets acquired from TGS Development, L.P. (our 2011 acquisitions are discussed further in Note 2 to our consolidated financial statements included elsewhere in this report).  In the first nine months of 2010, we spent $1,172.8 million for strategic business acquisitions, primarily consisting of the following: (i) $921.4 million for our initial 50% ownership interest in KinderHawk in May 2010; (ii) $114.3 million for three unit train ethanol handling terminals acquired from US Development Group LLC in January 2010; and (iii) $97.0 million for terminal assets and investments acquired from Slay Industries in March 2010;

 

▪

a $34.0 million increase in cash from higher proceeds received for combined margin and restricted deposits, primarily due to a $50.0 million increase due to the release of restricted cash.  As of December 31, 2010, we placed the $50.0 million cash we paid in January 2011 for our equity investment in Watco Companies, LLC in a cash escrow account, and we reported this amount as “Restricted deposits” on our year-end balance sheet;

 

▪

a $12.1 million increase in cash due to higher capital distributions (distributions in excess of cumulative earnings) received from equity investments in the first nine months of 2011—chiefly due to incremental capital distributions received from Fayetteville Express Pipeline LLC;

 

▪

a $115.6 million decrease in cash due to higher capital expenditures, as described above in “—Capital Expenditures;” and

 

▪

an $87.2 million decrease in cash due to higher contributions to equity investees.  During the first nine months of 2011, we contributed $297.0 million to our equity investees, including payments of $195.0 million to Fayetteville Express Pipeline LLC and $73.5 million to our 50%-owned Eagle Ford Gathering LLC.  Fayetteville Express used the contributions to repay borrowings under its previous $1.1 billion bank credit facility, and subsequently, entered into new borrowing facilities.  Eagle Ford Gathering used the contributions as partial funding for natural gas gathering infrastructure expansions.  In the first nine months of 2010, we contributed an aggregate amount of $209.8 million, including $130.5 million to Rockies Express Pipeline LLC and $39.0 million to Midcontinent Express Pipeline LLC to partially fund our respective share of Rockies Express and Midcontinent Express natural gas pipeline system construction costs.

 

 

table of content

69

---

 

Financing Activities

 

Net cash provided from financing activities amounted to $8.3 million for the first nine months of 2011, and for the same comparable period last year, we provided net cash of $425.0 million from our financing activities. The $416.7 million (98%) overall decrease in cash was mainly due to:

 

▪

a $359.9 million decrease in cash due to higher partnership distributions.  Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our noncontrolling interests, totaled $1,659.3 million in the first nine months of 2011.  In the first nine months of 2010, we distributed $1,299.4 million to our partners.  Further information regarding our distributions is discussed following in “—Partnership Distributions;”

 

▪

a $252.0 million decrease in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs.  The decrease in cash was primarily due to (i) a $283.8 million decrease due to lower net short-term borrowings (consisting of borrowings and repayments under both our commercial paper program and our revolving credit facility); (ii) a $154.0 million decrease due to the repayment of all of the outstanding borrowings under KinderHawk Field Services LLC’s bank credit facility that we assumed on our July 1, 2011 acquisition date; (iii) a $142.9 million increase due to higher net issuances and repayments of our senior notes (in the first nine months of 2011, we generated net proceeds of $1,136.0 million from issuing and repaying senior notes, and in May 2010, we received net proceeds of $993.1 million from the public offering of $1.0 billion aggregate principal amount of senior notes); and (iv) a $30.9 million increase in cash due to higher repayments received in the first nine months of 2011 on a related party loan we made in July 2004 to Plantation Pipe Line Company.

 

Due in part to our short-term credit rating upgrade in February 2011, we made no short-term borrowings under our revolving credit facility in the first nine months of 2011, but instead made borrowings under our commercial paper program.  For more information about our debt financing activities, see Note 4 “Debt” to our consolidated financial statements included elsewhere in this report;

 

▪

a $176.7 million increase in cash due to higher partnership equity issuances.  The increase reflects the $813.3 million we received, after commissions and underwriting expenses, from the sales of additional common units in the first nine months of 2011 (discussed in Note 5 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report), versus the $636.6 million we received from the sales of additional common units in the same nine month period a year ago.  We used the proceeds from our 2011 equity issuances to reduce the borrowings under our commercial paper program, and in 2010, to reduce the borrowings under both our commercial paper program and our credit facility; and

 

▪

a $12.8 million increase in cash from net changes in cash book overdrafts, resulting from timing differences on checks issued but not yet presented for payment.

 

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.

 

table of content

70

---

 

On August 12, 2011, we paid a quarterly distribution of $1.15 per unit for the second quarter of 2011.  This distribution was 6% greater than the $1.09 distribution per unit we paid on August 13, 2010 for the second quarter of 2010.  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 $1.15 cash distribution per common unit.

 

The incentive distribution that we paid on August 12, 2011 to our general partner (for the second quarter of 2011) totaled $292.8 million, and the incentive distribution that we paid in August 2010 (for the second quarter of 2010) totaled $89.8 million.  The increase in the incentive distribution paid to our general partner for the second quarter of 2011 versus the second 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.   Additionally, our second quarter 2010 incentive distribution was reduced by $168.3 million due to a portion ($177.1 million) of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations.  There was no practical impact to our limited partners from this distribution of cash from interim capital transactions; however, a s provided in our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions (including the general partner’s 2% general partner interest, its total cash distributions were reduced by $170.0 million).

 

Our second quarter 2011 and 2010 general partner incentive distributions were also reduced by waived incentive distribution amounts of $7.1 million and $5.3 million, respectively, related to common units issued to finance a portion of our May 2010 acquisition of an initial 50% ownership interest in KinderHawk Field Services LLC.  O ur general partner has agreed (i) to forego all incentive distributions related to this initial 50% joint venture acquisition through year-end 2011; and (ii) to forego incremental incentive distributions of approximately $26 million in 2012 and approximately $4 million in 2013 related to our subsequent acquisition of the remaining 50% ownership interest in KinderHawk Field Services LLC (effective July 1, 2011).

 

On October 19, 2011, we declared a cash distribution of $1.16 per unit for the third quarter of 2011 (an annualized rate of $4.64 per unit).  This distribution is 4.5% higher than the $1.11 per unit distribution we made for the third quarter of 2010.  For more information about our third quarter 2011 and third quarter 2010 cash distributions, see Note 5 “Partners’ Capital—Subsequent Events” to our consolidated financial statements included elsewhere in this report.

Currently, we expect to declare cash distributions in excess of $4.60 per unit for 2011 (for 2010, we made cash distributions of $4.40 per unit, and our 2011 budget assumes cash distributions of $4.60 per unit).  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 2011 budget 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 approximately $93 per barrel in 2011.  Furthermore, 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 and Fayetteville 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.

 

table of content

71

---

 

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:

 

▪

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 standards 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;

 

▪

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

 

table of content

72

---

 

 

▪

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.

 

 

table of content

73

---

 

 

Item 4.   Controls and Procedures.

 

As of September 30, 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 September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

table of content

74

---

 

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 4.150% Senior Notes due March 1, 2022, and the 5.625% Senior Notes due September 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.
	*10.1—	First Amendment to Credit Agreement, dated as of July 1, 2011, among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. "B", the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2011 (File No. 1-11234)).
	11 —	Statement re: computation of per share earnings.
	12 —	Statement re: computation of ratio of earnings to fixed charges.
	31.1—	Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2—	Certification by CFO pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1—	Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2—	Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101 —	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010; (ii) our Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010; (iii) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; and (iv) the notes to our Consolidated Financial Statements.

____________

 

 

table of content

75

---

 

* Asterisk indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.

table of content

76

---

 

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:  October 28, 2011				By:		/s/ Kimberly A. Dang
						Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)

 

table of content

77

---