Delaware
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76-0380342
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Page
Number
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PART I. FINANCIAL INFORMATION
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Item 1.
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Financial Statements (Unaudited)
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3
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Consolidated Statements of Income - Three and Nine Months Ended September 30, 2011 and 2010
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Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
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Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2011 and 2010
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Notes to Consolidated Financial Statements
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Item 2.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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47
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General and Basis of Presentation
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Critical Accounting Policies and Estimates
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Results of Operations
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Financial Condition
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Recent Accounting Pronouncements
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Information Regarding Forward-Looking Statements
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Item 3.
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Quantitative and Qualitative Disclosures About Market Risk
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Item 4.
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Controls and Procedures
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PART II. OTHER INFORMATION
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Item 1.
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Legal Proceedings
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Item 1A.
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Risk Factors
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Item 2.
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Unregistered Sales of Equity Securities and Use of Proceeds
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Item 3.
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Defaults Upon Senior Securities
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Item 4.
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(Removed and Reserved)
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Item 5.
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Other Information
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Item 6.
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Exhibits
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Signature
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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|||||||||||||||
2011
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2010
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2011
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2010
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|||||||||||||
Revenues
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||||||||||||||||
Natural gas sales
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$ | 938.9 | $ | 965.7 | $ | 2,594.9 | $ | 2,831.3 | ||||||||
Services
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780.1 | 758.7 | 2,317.6 | 2,248.9 | ||||||||||||
Product sales and other
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476.1 | 335.6 | 1,294.7 | 1,070.9 | ||||||||||||
Total Revenues
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2,195.1 | 2,060.0 | 6,207.2 | 6,151.1 | ||||||||||||
Operating Costs, Expenses and Other
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||||||||||||||||
Gas purchases and other costs of sales
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942.5 | 964.6 | 2,641.5 | 2,829.2 | ||||||||||||
Operations and maintenance
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411.8 | 328.3 | 1,199.9 | 1,098.7 | ||||||||||||
Depreciation, depletion and amortization
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253.4 | 224.1 | 704.6 | 674.6 | ||||||||||||
General and administrative
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100.5 | 93.6 | 387.1 | 288.1 | ||||||||||||
Taxes, other than income taxes
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38.9 | 41.9 | 140.8 | 128.1 | ||||||||||||
Other expense (income)
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(0.9 | ) | 0.2 | (14.9 | ) | (6.4 | ) | |||||||||
Total Operating Costs, Expenses and Other
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1,746.2 | 1,652.7 | 5,059.0 | 5,012.3 | ||||||||||||
Operating Income
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448.9 | 407.3 | 1,148.2 | 1,138.8 | ||||||||||||
Other Income (Expense)
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||||||||||||||||
Earnings from equity investments
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72.6 | 53.7 | 213.9 | 155.6 | ||||||||||||
Amortization of excess cost of equity investments
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(1.8 | ) | (1.4 | ) | (4.9 | ) | (4.3 | ) | ||||||||
Interest expense
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(133.4 | ) | (134.0 | ) | (395.6 | ) | (374.9 | ) | ||||||||
Interest income
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6.3 | 5.0 | 17.4 | 17.5 | ||||||||||||
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)
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(167.2 | ) | - | (167.2 | ) | - | ||||||||||
Other, net
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3.1 | 5.4 | 11.1 | 9.8 | ||||||||||||
Total Other Income (Expense)
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(220.4 | ) | (71.3 | ) | (325.3 | ) | (196.3 | ) | ||||||||
Income Before Income Taxes
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228.5 | 336.0 | 822.9 | 942.5 | ||||||||||||
Income Tax (Expense) Benefit
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(12.2 | ) | (13.6 | ) | (33.8 | ) | (27.6 | ) | ||||||||
Net Income
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216.3 | 322.4 | 789.1 | 914.9 | ||||||||||||
Net Income Attributable to Noncontrolling Interests
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(1.8 | ) | (1.6 | ) | (6.3 | ) | (7.6 | ) | ||||||||
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
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$ | 214.5 | $ | 320.8 | $ | 782.8 | $ | 907.3 | ||||||||
Calculation of Limited Partners’ Interest in Net Income (Loss)
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||||||||||||||||
Attributable to Kinder Morgan Energy Partners, L.P.:
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||||||||||||||||
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
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$ | 214.5 | $ | 320.8 | $ | 782.8 | $ | 907.3 | ||||||||
Less: General Partner’s Interest
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(298.2 | ) | (267.3 | ) | (871.0 | ) | (609.0 | ) | ||||||||
Limited Partners’ Interest in Net Income (Loss)
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$ | (83.7 | ) | $ | 53.5 | $ | (88.2 | ) | $ | 298.3 | ||||||
Limited Partners’ Net Income (Loss) per Unit
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$ | (0.25 | ) | $ | 0.17 | $ | (0.27 | ) | $ | 0.98 | ||||||
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit
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331.1 | 310.7 | 323.3 | 304.7 | ||||||||||||
Per Unit Cash Distribution Declared
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$ | 1.16 | $ | 1.11 | $ | 3.45 | $ | 3.27 |
September 30,
2011
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December 31, 2010
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|||||||
(Unaudited)
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||||||||
ASSETS
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||||||||
Current assets
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||||||||
Cash and cash equivalents
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$ | 271.0 | $ | 129.1 | ||||
Restricted deposits
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0.7 | 50.0 | ||||||
Accounts, notes and interest receivable, net
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823.6 | 951.8 | ||||||
Inventories
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101.3 | 92.0 | ||||||
Gas in underground storage
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27.2 | 2.2 | ||||||
Fair value of derivative contracts
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135.2 | 24.0 | ||||||
Other current assets
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47.0 | 37.6 | ||||||
Total current assets
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1,406.0 | 1,286.7 | ||||||
Property, plant and equipment, net
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15,344.1 | 14,603.9 | ||||||
Investments
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3,272.5 | 3,886.0 | ||||||
Notes receivable
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164.0 | 115.0 | ||||||
Goodwill
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1,303.3 | 1,233.6 | ||||||
Other intangibles, net
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1,167.5 | 302.2 | ||||||
Fair value of derivative contracts
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703.4 | 260.7 | ||||||
Deferred charges and other assets
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217.5 | 173.0 | ||||||
Total Assets
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$ | 23,578.3 | $ | 21,861.1 | ||||
LIABILITIES AND PARTNERS’ CAPITAL
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||||||||
Current liabilities
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||||||||
Current portion of debt
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$ | 1,844.4 | $ | 1,262.4 | ||||
Cash book overdrafts
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40.9 | 32.5 | ||||||
Accounts payable
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624.4 | 630.9 | ||||||
Accrued interest
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96.9 | 239.6 | ||||||
Accrued taxes
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100.6 | 44.7 | ||||||
Deferred revenues
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91.9 | 96.6 | ||||||
Fair value of derivative contracts
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71.9 | 281.5 | ||||||
Accrued other current liabilities
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199.3 | 176.0 | ||||||
Total current liabilities
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3,070.3 | 2,764.2 | ||||||
Long-term liabilities and deferred credits
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||||||||
Long-term debt
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||||||||
Outstanding
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10,662.2 | 10,277.4 | ||||||
Value of interest rate swaps
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1,071.2 | 604.9 | ||||||
Total Long-term debt
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11,733.4 | 10,882.3 | ||||||
Deferred income taxes
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243.0 | 248.3 | ||||||
Fair value of derivative contracts
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21.4 | 172.2 | ||||||
Other long-term liabilities and deferred credits
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785.7 | 501.6 | ||||||
Total long-term liabilities and deferred credits
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12,783.5 | 11,804.4 | ||||||
Total Liabilities
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15,853.8 | 14,568.6 | ||||||
Commitments and contingencies (Notes 4 and 10)
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||||||||
Partners’ Capital
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||||||||
Common units
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4,354.7 | 4,282.2 | ||||||
Class B units
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44.9 | 63.1 | ||||||
i-units
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2,807.1 | 2,807.5 | ||||||
General partner
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257.7 | 244.3 | ||||||
Accumulated other comprehensive income (loss)
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172.6 | (186.4 | ) | |||||
Total Kinder Morgan Energy Partners, L.P. partners’ capital
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7,637.0 | 7,210.7 | ||||||
Noncontrolling interests
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87.5 | 81.8 | ||||||
Total Partners’ Capital
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7,724.5 | 7,292.5 | ||||||
Total Liabilities and Partners’ Capital
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$ | 23,578.3 | $ | 21,861.1 |
Nine Months Ended
September 30,
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||||||||
2011
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2010
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|||||||
Cash Flows From Operating Activities
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||||||||
Net Income
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$ | 789.1 | $ | 914.9 | ||||
Adjustments to reconcile net income to net cash provided by operating activities:
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||||||||
Depreciation, depletion and amortization
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704.6 | 674.6 | ||||||
Amortization of excess cost of equity investments
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4.9 | 4.3 | ||||||
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)
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167.2 | - | ||||||
Noncash compensation expense allocated from parent (Note 9)
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89.9 | 3.7 | ||||||
Earnings from equity investments
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(213.9 | ) | (155.6 | ) | ||||
Distributions from equity investments
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200.9 | 154.9 | ||||||
Proceeds from termination of interest rate swap agreements
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73.0 | - | ||||||
Changes in components of working capital:
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||||||||
Accounts receivable
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28.2 | 105.0 | ||||||
Inventories
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9.3 | (12.8 | ) | |||||
Other current assets
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(1.8 | ) | 12.9 | |||||
Accounts payable
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(9.3 | ) | (26.8 | ) | ||||
Accrued interest
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(142.8 | ) | (125.6 | ) | ||||
Accrued taxes
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47.4 | 32.7 | ||||||
Accrued liabilities
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(2.4 | ) | 2.8 | |||||
Rate reparations, refunds and other litigation reserve adjustments
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160.4 | (48.3 | ) | |||||
Other, net
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70.4 | (9.4 | ) | |||||
Net Cash Provided by Operating Activities
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1,975.1 | 1,527.3 | ||||||
Cash Flows From Investing Activities
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||||||||
Acquisitions of investments
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(901.0 | ) | (929.7 | ) | ||||
Acquisitions of assets
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(44.0 | ) | (243.1 | ) | ||||
Capital expenditures
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(837.7 | ) | (722.1 | ) | ||||
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
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29.0 | 21.5 | ||||||
Net proceeds from margin and restricted deposits
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55.7 | 21.7 | ||||||
Contributions to equity investments
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(297.0 | ) | (209.8 | ) | ||||
Distributions from equity investments in excess of cumulative earnings
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165.3 | 153.2 | ||||||
Other, net
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3.0 | - | ||||||
Net Cash Used in Investing Activities
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(1,826.7 | ) | (1,908.3 | ) | ||||
Cash Flows From Financing Activities
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||||||||
Issuance of debt
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6,356.4 | 5,704.2 | ||||||
Payment of debt
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(5,538.1 | ) | (4,601.0 | ) | ||||
Repayments from related party
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29.3 | 1.3 | ||||||
Debt issue costs
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(17.6 | ) | (22.5 | ) | ||||
Increase (Decrease) in cash book overdrafts
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8.4 | (4.4 | ) | |||||
Proceeds from issuance of common units
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813.3 | 636.6 | ||||||
Contributions from noncontrolling interests
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15.4 | 10.2 | ||||||
Distributions to partners and noncontrolling interests:
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||||||||
Common units
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(762.1 | ) | (674.2 | ) | ||||
Class B units
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(18.2 | ) | (17.1 | ) | ||||
General Partner
|
(858.5 | ) | (591.4 | ) | ||||
Noncontrolling interests
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(20.5 | ) | (16.7 | ) | ||||
Other, net
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0.5 | - | ||||||
Net Cash Provided by Financing Activities
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8.3 | 425.0 | ||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents
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(14.8 | ) | 1.0 | |||||
Net increase in Cash and Cash Equivalents
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141.9 | 45.0 | ||||||
Cash and Cash Equivalents, beginning of period
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129.1 | 146.6 | ||||||
Cash and Cash Equivalents, end of period
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$ | 271.0 | $ | 191.6 |
Nine Months Ended
September 30,
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||||||||
2011
|
2010
|
|||||||
Noncash Investing and Financing Activities
|
||||||||
Assets acquired by the assumption or incurrence of liabilities
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$ | 179.5 | $ | 12.5 | ||||
Assets acquired by the issuance of common units
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$ | 23.7 | $ | 81.7 | ||||
Contribution of net assets to investments
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$ | 7.9 | $ | - | ||||
Sale of investment ownership interest in exchange for note
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$ | 4.1 | $ | - | ||||
Supplemental Disclosures of Cash Flow Information
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||||||||
Cash paid during the period for interest (net of capitalized interest)
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$ | 510.2 | $ | 456.6 | ||||
Cash paid during the period for income taxes
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$ | 9.4 | $ | (2.8 | ) |
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▪
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$35.5 million to current assets, primarily consisting of trade receivables and materials and supplies inventory;
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▪
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$641.6 million to property, plant and equipment;
|
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▪
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$93.4 million to our 25% investment in EagleHawk;
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▪
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$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
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▪
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$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.
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Products
Pipelines
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Natural Gas
Pipelines
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CO2
|
Terminals
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Kinder Morgan
Canada
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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.
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(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).
|
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 |
|
Kinder Morgan Energy Partners, L.P. Senior Notes
|
|
Subsidiary Debt
|
|
▪
|
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.
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|
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.
|
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 |
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 |
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.
|
|
▪
|
$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.
|
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
|
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 | ) |
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 |
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 |
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 |
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.
|
|
▪
|
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).
|
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.
|
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 |
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 |
|
▪
|
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;
|
|
▪
|
CO2—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.
|
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 | ||||||||||||
CO2
|
||||||||||||||||
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 | ||||||||||||
CO2
|
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 | ||||||
CO2
|
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.
|
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 | ) |
|
SFPP
|
|
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.
|
|
Calnev
|
|
▪
|
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
|
|
Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding
|
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 | )% | ||||||||||
CO2(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 | )% | ||||||||||
CO2(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 | )% |
(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.
|
(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.
|
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 |
(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.
|
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 | % |
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 | % |
|
▪
|
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.
|
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.
|
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 | % |
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 | )% |
(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.
|
|
▪
|
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;
|
|
▪
|
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).
|
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.
|
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 CO2
|
$ | 56.9 | 25 | % | $ | 59.6 | 20 | % |
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 CO2
|
$ | 94.1 | 13 | % | $ | 125.4 | 14 | % |
|
▪
|
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.
|
|
▪
|
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.
|
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.
|
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 | % |
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 | % |
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.
|
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 | % |
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.
|
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.”
|
|
▪
|
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.
|
|
▪
|
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.
|
|
▪
|
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.
|
|
▪
|
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.
|
|
▪
|
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.
|
|
▪
|
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;
|
|
▪
|
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.
|
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.
|
|
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)
|
|
(1)
|
the sum of the present values, calculated as of the Redemption Date, of:
|
|
•
|
each interest payment that, but for the redemption, would have been payable on the Note, or portion of a Note, being redeemed on each interest payment date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and
|
|
•
|
the principal amount that, but for the redemption, would have been payable at the stated maturity of the Note, or portion of a Note, being redeemed;
|
|
(2)
|
the principal amount of the Note, or portion of a Note, being redeemed.
|
|
the sum of the present values, calculated as of the Redemption Date, of:
|
·
|
each interest payment that, but for the redemption, would have been payable on the Security, or portion of a Security, being redeemed on each Interest Payment Date occurring after the Redemption Date, excluding any accrued interest for the period prior to the Redemption Date; and
|
·
|
the principal amount that, but for the redemption, would have been payable at the Stated Maturity of the Security, or portion of a Security, being redeemed;
|
|
the principal amount of the Security, or portion of a Security, being redeemed.
|
Three Months Ended September 30,
|
||||||||
|
2011
|
2010
|
||||||
Weighted Average Number of Limited Partners’ Units on which Limited Partners’ Net Income (Loss) per Unit is Based
|
331.1 | 310.7 | ||||||
Calculation of Limited Partners’ interest in Net Income (Loss)
|
||||||||
Amounts Attributable to Kinder Morgan Energy Partners, L.P.:
|
||||||||
Net Income
|
$ | 214.5 | $ | 320.8 | ||||
Less: General Partner’s interest in Net Income
|
(298.2 | ) | (267.3 | ) | ||||
Limited Partners’ interest in Net Income (Loss)
|
$ | (83.7 | ) | $ | 53.5 | |||
Limited Partners’ Net Income (Loss) per Unit
|
$ | (0.25 | ) | $ | 0.17 |
Nine Months Ended September 30,
|
||||||||
|
2011
|
2010
|
||||||
Weighted Average Number of Limited Partners’ Units on which Limited Partners’ Net Income (Loss) per Unit is Based
|
323.3 | 304.7 | ||||||
Calculation of Limited Partners’ interest in Net Income (Loss)
|
||||||||
Amounts Attributable to Kinder Morgan Energy Partners, L.P.:
|
||||||||
Net Income
|
$ | 782.8 | $ | 907.3 | ||||
Less: General Partner’s interest in Net Income
|
(871.0 | ) | (609.0 | ) | ||||
Limited Partners’ interest in Net Income (Loss)
|
$ | (88.2 | ) | $ | 298.3 | |||
Limited Partners’ Net Income (Loss) per Unit
|
$ | (0.27 | ) | $ | 0.98 |
Nine Months Ended
|
Nine Months Ended
|
|||||||
|
September 30, 2011
|
September 30, 2010
|
||||||
Earnings:
Pre-tax income from continuing operations before adjustment for noncontrolling interests and equity earnings (including amortization of excess cost of equity investments) per statements of income
|
$ | 613.9 | $ | 791.2 | ||||
Add:
|
||||||||
Fixed charges
|
447.3 | 400.9 | ||||||
Amortization of capitalized interest
|
3.2 | 3.0 | ||||||
Distributed income of equity investees
|
200.9 | 154.9 | ||||||
Less:
|
||||||||
Interest capitalized from continuing operations
|
(9.7 | ) | (9.8 | ) | ||||
Noncontrolling interests in pre-tax income of subsidiaries
with no fixed charges
|
(0.4 | ) | (0.2 | ) | ||||
Income as adjusted
|
$ | 1,255.2 | $ | 1,340.0 | ||||
Fixed charges:
Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)
|
$ | 405.3 | $ | 384.8 | ||||
Add:
|
||||||||
Portion of rents representative of the interest factor
|
42.0 | 16.1 | ||||||
Fixed charges
|
$ | 447.3 | $ | 400.9 | ||||
Ratio of earnings to fixed charges
|
2.81 | 3.34 | ||||||
1.
|
I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;
|
c)
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States;
|
c)
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Document And Entity Information (USD $) | 9 Months Ended | ||
---|---|---|---|
Sep. 30, 2011 | Oct. 28, 2011 | Jun. 30, 2010 | |
Entity Registrant Name | Kinder Morgan Energy Partners L P | ||
Entity Central Index Key | 0000888228 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 12,836,486,727 | ||
Entity Common Stock, Shares Outstanding | 230,901,187 | ||
Document Fiscal Year Focus | 2011 | ||
Document Fiscal Period Focus | Q3 | ||
Document Type | 10-Q | ||
Amendment Flag | false | ||
Document Period End Date | Sep. 30, 2011 |
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'+ "\n"+' | '+ "\n"+' '+ "\n"+'
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Reportable Segments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reportable Segments [Text Block] | 8. Reportable Segments We divide our operations into five reportable business segments. These segments and their principal source of revenues are as follows:
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. Financial information by segment follows (in millions):
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Goodwill | 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):
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Other Intangibles | 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):
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Debt [Text Block] | 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.
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.
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. 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:
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. 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. |
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Litigation, Environmental and Other Contingencies [Text Block] | 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. 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 CO2 Company, L.P. (the successor to Shell CO2 Company, Ltd.) as Kinder Morgan CO2; 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.
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.
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.
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:
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.
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. 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 CO2. The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO2 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 CO2 protested the Notices of Deficiency and paid the tax and interest under protest. Kinder Morgan CO2 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 CO2, 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 CO2'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 CO2 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 CO2 will vigorously contest the retroactive tax bills. Other In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2's payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing. These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado. 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. 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 61st 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. 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. 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. 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. 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. 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. 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. |
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Outstanding Commodity Forward Contracts | As of September 30, 2011, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
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Fair Value of Derivative Contracts | 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):
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Effect of Derivative Contracts on the Income Statement | 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):
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Maximum Potential Exposure to Credit Losses on our Derivative Contracts | The maximum potential exposure to credit losses on our derivative contracts as of September 30, 2011 was (in millions):
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Additional Collateral Obligations |
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Regulatory Matters | 9 Months Ended |
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Sep. 30, 2011 | |
Regulatory Matters [Abstract] | |
Regulatory Matters [Text Block] | 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. 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. |
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