Delaware
|
76-0380342
|
|
(State or other jurisdiction of
incorporation or organization)
|
(I.R.S. Employer
Identification No.)
|
Page
Number
|
||
PART I. FINANCIAL INFORMATION
|
||
Item 1.
|
Financial Statements (Unaudited)
|
3
|
Consolidated Statements of Income - Three and Six Months Ended June 30, 2010 and 2009
|
3
|
|
Consolidated Balance Sheets - June 30, 2010 and December 31, 2009
|
4
|
|
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2010 and 2009
|
5
|
|
Notes to Consolidated Financial Statements
|
6
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
41
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General and Basis of Presentation
|
41
|
|
Critical Accounting Policies and Estimates
|
42
|
|
Results of Operations
|
43
|
|
Financial Condition
|
56
|
|
Recent Accounting Pronouncements
|
63
|
|
Information Regarding Forward-Looking Statements
|
63
|
|
Item 3.
|
Quantitative and Qualitative Disclosures About Market Risk
|
65
|
Item 4.
|
Controls and Procedures
|
65
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PART II. OTHER INFORMATION
|
||
Item 1.
|
Legal Proceedings
|
66
|
Item 1A.
|
Risk Factors
|
66
|
Item 2.
|
Unregistered Sales of Equity Securities and Use of Proceeds
|
66
|
Item 3.
|
Defaults Upon Senior Securities
|
66
|
Item 4.
|
(Removed and Reserved)
|
66
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Item 5.
|
Other Information
|
66
|
Item 6.
|
Exhibits
|
66
|
Signature
|
68
|
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Revenues
|
||||||||||||||||
Natural gas sales
|
$ | 848.1 | $ | 716.9 | $ | 1,865.6 | $ | 1,605.6 | ||||||||
Services
|
751.7 | 652.1 | 1,490.2 | 1,313.5 | ||||||||||||
Product sales and other
|
361.7 | 276.3 | 735.3 | 512.7 | ||||||||||||
Total Revenues
|
1,961.5 | 1,645.3 | 4,091.1 | 3,431.8 | ||||||||||||
Operating Costs, Expenses and Other
|
||||||||||||||||
Gas purchases and other costs of sales
|
848.0 | 709.6 | 1,864.6 | 1,575.3 | ||||||||||||
Operations and maintenance
|
317.5 | 267.3 | 770.4 | 517.3 | ||||||||||||
Depreciation, depletion and amortization
|
223.2 | 203.1 | 450.5 | 413.3 | ||||||||||||
General and administrative
|
93.4 | 72.6 | 194.5 | 155.1 | ||||||||||||
Taxes, other than income taxes
|
41.1 | 23.4 | 86.2 | 62.4 | ||||||||||||
Other expense (income)
|
(5.3 | ) | (2.7 | ) | (6.6 | ) | (3.6 | ) | ||||||||
Total Operating Costs, Expenses and Other
|
1,517.9 | 1,273.3 | 3,359.6 | 2,719.8 | ||||||||||||
Operating Income
|
443.6 | 372.0 | 731.5 | 712.0 | ||||||||||||
Other Income (Expense)
|
||||||||||||||||
Earnings from equity investments
|
55.2 | 41.9 | 101.9 | 80.1 | ||||||||||||
Amortization of excess cost of equity investments
|
(1.5 | ) | (1.5 | ) | (2.9 | ) | (2.9 | ) | ||||||||
Interest, net
|
(116.9 | ) | (96.0 | ) | (228.4 | ) | (193.2 | ) | ||||||||
Other, net
|
(2.3 | ) | 20.2 | 4.4 | 30.9 | |||||||||||
Total Other Income (Expense)
|
(65.5 | ) | (35.4 | ) | (125.0 | ) | (85.1 | ) | ||||||||
Income Before Income Taxes
|
378.1 | 336.6 | 606.5 | 626.9 | ||||||||||||
Income Taxes
|
(13.0 | ) | (8.0 | ) | (14.0 | ) | (31.5 | ) | ||||||||
Net Income
|
365.1 | 328.6 | 592.5 | 595.4 | ||||||||||||
Net Income Attributable to Noncontrolling Interests
|
(3.9 | ) | (4.8 | ) | (6.0 | ) | (7.7 | ) | ||||||||
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
|
$ | 361.2 | $ | 323.8 | $ | 586.5 | $ | 587.7 | ||||||||
Calculation of Limited Partners’ Interest in Net Income
|
||||||||||||||||
Attributable to Kinder Morgan Energy Partners, L.P.:
|
||||||||||||||||
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
|
$ | 361.2 | $ | 323.8 | $ | 586.5 | $ | 587.7 | ||||||||
Less: General Partner’s Interest
|
(92.5 | ) | (232.8 | ) | (341.7 | ) | (456.5 | ) | ||||||||
Limited Partners’ Interest in Net Income
|
$ | 268.7 | $ | 91.0 | $ | 244.8 | $ | 131.2 | ||||||||
Limited Partners’ Net Income per Unit
|
$ | 0.88 | $ | 0.33 | $ | 0.81 | $ | 0.48 | ||||||||
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit
|
304.5 | 277.5 | 301.7 | 273.5 | ||||||||||||
Per Unit Cash Distribution Declared
|
$ | 1.09 | $ | 1.05 | $ | 2.16 | $ | 2.10 |
June 30,
2010
|
December 31,
2009 |
|||||||
(Unaudited)
|
||||||||
ASSETS
|
||||||||
Current assets
|
||||||||
Cash and cash equivalents
|
$ | 143.1 | $ | 146.6 | ||||
Restricted deposits
|
19.3 | 15.2 | ||||||
Accounts, notes and interest receivable, net
|
834.7 | 902.1 | ||||||
Inventories
|
101.5 | 71.9 | ||||||
Gas in underground storage
|
50.8 | 43.5 | ||||||
Fair value of derivative contracts
|
44.5 | 20.8 | ||||||
Other current assets
|
39.5 | 44.6 | ||||||
Total current assets
|
1,233.4 | 1,244.7 | ||||||
Property, plant and equipment, net
|
14,308.2 | 14,153.8 | ||||||
Investments
|
3,855.4 | 2,845.2 | ||||||
Notes receivable
|
188.5 | 190.6 | ||||||
Goodwill
|
1,205.0 | 1,149.2 | ||||||
Other intangibles, net
|
315.5 | 218.7 | ||||||
Fair value of derivative contracts
|
544.4 | 279.8 | ||||||
Deferred charges and other assets
|
177.9 | 180.2 | ||||||
Total Assets
|
$ | 21,828.3 | $ | 20,262.2 | ||||
LIABILITIES AND PARTNERS’ CAPITAL
|
||||||||
Current liabilities
|
||||||||
Current portion of debt
|
$ | 1,571.1 | $ | 594.7 | ||||
Cash book overdrafts
|
42.8 | 34.8 | ||||||
Accounts payable
|
564.0 | 614.8 | ||||||
Accrued interest
|
232.8 | 222.4 | ||||||
Accrued taxes
|
56.2 | 57.8 | ||||||
Deferred revenues
|
78.1 | 76.0 | ||||||
Fair value of derivative contracts
|
189.1 | 272.0 | ||||||
Accrued other current liabilities
|
145.9 | 145.1 | ||||||
Total current liabilities
|
2,880.0 | 2,017.6 | ||||||
Long-term liabilities and deferred credits
|
||||||||
Long-term debt
|
||||||||
Outstanding
|
10,279.7 | 9,997.7 | ||||||
Value of interest rate swaps
|
737.5 | 332.5 | ||||||
Total Long-term debt
|
11,017.2 | 10,330.2 | ||||||
Deferred income taxes
|
221.3 | 216.8 | ||||||
Fair value of derivative contracts
|
150.3 | 460.1 | ||||||
Other long-term liabilities and deferred credits
|
453.3 | 513.4 | ||||||
Total long-term liabilities and deferred credits
|
11,842.1 | 11,520.5 | ||||||
Total Liabilities
|
14,722.1 | 13,538.1 | ||||||
Commitments and contingencies (Notes 4 and 10)
|
||||||||
Partners’ Capital
|
||||||||
Common units
|
4,305.4 | 4,057.9 | ||||||
Class B units
|
71.6 | 78.6 | ||||||
i-units
|
2,752.9 | 2,681.7 | ||||||
General partner
|
64.6 | 221.1 | ||||||
Accumulated other comprehensive loss
|
(171.4 | ) | (394.8 | ) | ||||
Total Kinder Morgan Energy Partners, L.P. partners’ capital
|
7,023.1 | 6,644.5 | ||||||
Noncontrolling interests
|
83.1 | 79.6 | ||||||
Total Partners’ Capital
|
7,106.2 | 6,724.1 | ||||||
Total Liabilities and Partners’ Capital
|
$ | 21,828.3 | $ | 20,262.2 |
Six Months Ended
June 30,
|
||||||||
2010
|
2009
|
|||||||
Cash Flows From Operating Activities
|
||||||||
Net Income
|
$ | 592.5 | $ | 595.4 | ||||
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||
Depreciation, depletion and amortization
|
450.5 | 413.3 | ||||||
Amortization of excess cost of equity investments
|
2.9 | 2.9 | ||||||
Income from the allowance for equity funds used during construction
|
(0.6 | ) | (20.3 | ) | ||||
Income from the sale or casualty of property, plant and equipment and other net assets
|
(6.6 | ) | (3.6 | ) | ||||
Earnings from equity investments
|
(101.9 | ) | (80.1 | ) | ||||
Distributions from equity investments
|
101.9 | 100.3 | ||||||
Proceeds from termination of interest rate swap agreements
|
- | 144.4 | ||||||
Changes in components of working capital:
|
||||||||
Accounts receivable
|
62.9 | 184.5 | ||||||
Inventories
|
(29.7 | ) | (11.2 | ) | ||||
Other current assets
|
(20.8 | ) | (68.2 | ) | ||||
Accounts payable
|
(42.7 | ) | (278.4 | ) | ||||
Accrued interest
|
10.3 | 21.2 | ||||||
Accrued taxes
|
(2.2 | ) | 3.4 | |||||
Accrued liabilities
|
(13.0 | ) | (24.3 | ) | ||||
Rate reparations, refunds and other litigation reserve adjustments
|
(48.3 | ) | (15.5 | ) | ||||
Other, net
|
(23.0 | ) | (27.0 | ) | ||||
Net Cash Provided by Operating Activities
|
932.2 | 936.8 | ||||||
Cash Flows From Investing Activities
|
||||||||
Acquisitions of investments
|
(929.7 | ) | - | |||||
Acquisitions of assets
|
(218.1 | ) | (18.5 | ) | ||||
Repayments from customers
|
- | 109.6 | ||||||
Capital expenditures
|
(451.1 | ) | (796.6 | ) | ||||
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
|
22.5 | (4.7 | ) | |||||
Investments in margin deposits
|
(3.9 | ) | (24.9 | ) | ||||
Contributions to equity investments
|
(180.9 | ) | (802.8 | ) | ||||
Distributions from equity investments in excess of cumulative earnings
|
93.3 | - | ||||||
Net Cash Used in Investing Activities
|
(1,667.9 | ) | (1,537.9 | ) | ||||
Cash Flows From Financing Activities
|
||||||||
Issuance of debt
|
4,709.5 | 3,237.1 | ||||||
Payment of debt
|
(3,443.0 | ) | (2,392.8 | ) | ||||
Repayments from related party
|
1.3 | 2.5 | ||||||
Debt issue costs
|
(22.3 | ) | (5.6 | ) | ||||
Increase (Decrease) in cash book overdrafts
|
8.1 | (21.6 | ) | |||||
Proceeds from issuance of common units
|
433.2 | 669.5 | ||||||
Contributions from noncontrolling interests
|
7.2 | 8.6 | ||||||
Distributions to partners and noncontrolling interests:
|
||||||||
Common units
|
(439.5 | ) | (391.4 | ) | ||||
Class B units
|
(11.3 | ) | (11.2 | ) | ||||
General Partner
|
(498.2 | ) | (445.5 | ) | ||||
Noncontrolling interests
|
(12.0 | ) | (10.8 | ) | ||||
Other, net
|
- | (0.2 | ) | |||||
Net Cash Provided by Financing Activities
|
733.0 | 638.6 | ||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
(0.8 | ) | 2.5 | |||||
(Decrease) Increase in Cash and Cash Equivalents
|
(3.5 | ) | 40.0 | |||||
Cash and Cash Equivalents, beginning of period
|
146.6 | 62.5 | ||||||
Cash and Cash Equivalents, end of period
|
$ | 143.1 | $ | 102.5 | ||||
Noncash Investing and Financing Activities
|
||||||||
Assets acquired by the assumption or incurrence of liabilities
|
$ | 8.1 | $ | 3.7 | ||||
Assets acquired by the issuance of common units
|
$ | 81.7 | $ | 5.0 | ||||
Supplemental Disclosures of Cash Flow Information
|
||||||||
Cash paid during the period for interest (net of capitalized interest)
|
$ | 224.7 | $ | 205.5 | ||||
Cash paid during the period for income taxes
|
$ | 7.9 | $ | 8.2 |
Products
Pipelines
|
Natural Gas
Pipelines
|
CO
2
|
Terminals
|
Kinder
Morgan
Canada
|
Total
|
|||||||||||||||||||
Historical Goodwill
|
$ | 263.2 | $ | 337.0 | $ | 46.1 | $ | 266.9 | $ | 613.1 | $ | 1,526.3 | ||||||||||||
Accumulated impairment losses(a)
|
- | - | - | - | (377.1 | ) | (377.1 | ) | ||||||||||||||||
Balance as of December 31, 2009
|
263.2 | 337.0 | 46.1 | 266.9 | 236.0 | 1,149.2 | ||||||||||||||||||
Acquisitions
|
- | - | - | 58.9 | - | 58.9 | ||||||||||||||||||
Currency translation adjustments
|
- | - | - | - | (3.1 | ) | (3.1 | ) | ||||||||||||||||
Balance as of June 30, 2010
|
$ | 263.2 | $ | 337.0 | $ | 46.1 | $ | 325.8 | $ | 232.9 | $ | 1,205.0 |
(a)
|
On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007. Following the provisions of generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on this determination, KMI recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment is now included in our accumulated impairment losses. We have no other goodwill impairment losses.
|
June 30,
2010
|
December 31,
2009
|
|||||||
Customer relationships, contracts and agreements
|
||||||||
Gross carrying amount
|
$ | 392.2 | $ | 273.0 | ||||
Accumulated amortization
|
(89.2 | ) | (67.1 | ) | ||||
Net carrying amount
|
303.0 | 205.9 | ||||||
Technology-based assets, lease value and other
|
||||||||
Gross carrying amount
|
15.7 | 15.7 | ||||||
Accumulated amortization
|
(3.2 | ) | (2.9 | ) | ||||
Net carrying amount
|
12.5 | 12.8 | ||||||
Total Other intangibles, net
|
$ | 315.5 | $ | 218.7 |
June 30,
|
December 31,
|
|||||||
2010
|
2009
|
|||||||
Common units
|
214,053,605 | 206,020,826 | ||||||
Class B units
|
5,313,400 | 5,313,400 | ||||||
i-units
|
88,670,863 | 85,538,263 | ||||||
Total limited partner units
|
308,037,868 | 296,872,489 |
Three Months Ended June 30,
|
||||||||||||||||||||||||
2010
|
2009
|
|||||||||||||||||||||||
KMP
|
Noncontrolling
interests
|
Total
|
KMP
|
Noncontrolling interests
|
Total
|
|||||||||||||||||||
Beginning Balance
|
$ | 6,612.6 | $ | 78.7 | $ | 6,691.3 | $ | 6,145.5 | $ | 71.6 | $ | 6,217.1 | ||||||||||||
Units issued as consideration in the acquisition of assets
|
- | - | - | 5.0 | - | 5.0 | ||||||||||||||||||
Units issued for cash
|
433.1 | - | 433.1 | 381.6 | - | 381.6 | ||||||||||||||||||
Distributions paid in cash
|
(480.2 | ) | (6.0 | ) | (486.2 | ) | (430.8 | ) | (5.4 | ) | (436.2 | ) | ||||||||||||
Adjustments to capital resulting from related party acquisitions
|
- | - | - | 20.2 | 0.3 | 20.5 | ||||||||||||||||||
KMI going-private transaction
expenses |
1.3 | - | 1.3 | 1.4 | - | 1.4 | ||||||||||||||||||
Cash contributions
|
- | 5.5 | 5.5 | - | 4.8 | 4.8 | ||||||||||||||||||
Other adjustments
|
- | - | - | (0.2 | ) | - | (0.2 | ) | ||||||||||||||||
Comprehensive income:
|
||||||||||||||||||||||||
Net Income
|
361.2 | 3.9 | 365.1 | 323.8 | 4.8 | 328.6 | ||||||||||||||||||
Other comprehensive income (loss):
|
||||||||||||||||||||||||
Change in fair value of derivatives utilized for hedging purposes
|
141.6 | 1.5 | 143.1 | (336.1 | ) | (3.4 | ) | (339.5 | ) | |||||||||||||||
Reclassification of change in fair
value of derivatives to net income |
39.1 | 0.4 | 39.5 | 30.3 | 0.3 | 30.6 | ||||||||||||||||||
Foreign currency translation
adjustments |
(85.5 | ) | (0.9 | ) | (86.4 | ) | 127.1 | 1.3 | 128.4 | |||||||||||||||
Adjustments to pension and other postretirement benefit plan
liabilities |
(0.1 | ) | - | (0.1 | ) | (0.1 | ) | - | (0.1 | ) | ||||||||||||||
Total other comprehensive income
(loss) |
95.1 | 1.0 | 96.1 | (178.8 | ) | (1.8 | ) | (180.6 | ) | |||||||||||||||
Comprehensive income
|
456.3 | 4.9 | 461.2 | 145.0 | 3.0 | 148.0 | ||||||||||||||||||
Ending Balance
|
$ | 7,023.1 | $ | 83.1 | $ | 7,106.2 | $ | 6,267.7 | $ | 74.3 | $ | 6,342.0 |
Six Months Ended June 30,
|
||||||||||||||||||||||||
2010
|
2009
|
|||||||||||||||||||||||
KMP
|
Noncontrolling
interests
|
Total
|
KMP
|
Noncontrolling interests
|
Total
|
|||||||||||||||||||
Beginning Balance
|
$ | 6,644.5 | $ | 79.6 | $ | 6,724.1 | $ | 6,045.6 | $ | 70.7 | $ | 6,116.3 | ||||||||||||
Units issued as consideration pursuant to common unit compensation plan
for non-employee directors |
0.2 | - | 0.2 | 0.2 | - | 0.2 | ||||||||||||||||||
Units issued as consideration in the acquisition of assets
|
81.7 | - | 81.7 | 5.0 | - | 5.0 | ||||||||||||||||||
Units issued for cash
|
433.1 | - | 433.1 | 669.2 | - | 669.2 | ||||||||||||||||||
Distributions paid in cash
|
(949.0 | ) | (12.0 | ) | (961.0 | ) | (848.1 | ) | (10.8 | ) | (858.9 | ) | ||||||||||||
Adjustments to capital resulting from related party acquisitions
|
- | - | - | 22.9 | 0.3 | 23.2 | ||||||||||||||||||
KMI going-private transaction
expenses |
2.7 | - | 2.7 | 2.8 | - | 2.8 | ||||||||||||||||||
Cash contributions
|
- | 7.2 | 7.2 | - | 8.6 | 8.6 | ||||||||||||||||||
Other adjustments
|
- | - | - | (0.2 | ) | - | (0.2 | ) | ||||||||||||||||
Comprehensive income:
|
||||||||||||||||||||||||
Net Income
|
586.5 | 6.0 | 592.5 | 587.7 | 7.7 | 595.4 | ||||||||||||||||||
Other comprehensive income (loss):
|
||||||||||||||||||||||||
Change in fair value of derivatives
utilized for hedging purposes |
166.0 | 1.7 | 167.7 | (300.6 | ) | (3.0 | ) | (303.6 | ) | |||||||||||||||
Reclassification of change in fair
value of derivatives to net income |
86.1 | 0.9 | 87.0 | 13.2 | 0.1 | 13.3 | ||||||||||||||||||
Foreign currency translation
adjustments |
(26.3 | ) | (0.3 | ) | (26.6 | ) | 72.9 | 0.7 | 73.6 | |||||||||||||||
Adjustments to pension and other postretirement benefit plan
liabilities |
(2.4 | ) | - | (2.4 | ) | (2.9 | ) | - | (2.9 | ) | ||||||||||||||
Total other comprehensive income
(loss) |
223.4 | 2.3 | 225.7 | (217.4 | ) | (2.2 | ) | (219.6 | ) | |||||||||||||||
Comprehensive income
|
809.9 | 8.3 | 818.2 | 370.3 | 5.5 | 375.8 | ||||||||||||||||||
Ending Balance
|
$ | 7,023.1 | $ | 83.1 | $ | 7,106.2 | $ | 6,267.7 | $ | 74.3 | $ | 6,342.0 |
Net open position
long/(short)
|
|
Derivatives designated as hedging contracts
|
|
Crude oil
|
(22.2) million barrels
|
Natural gas fixed price
|
(34.3) billion cubic feet
|
Natural gas basis
|
(28.1) billion cubic feet
|
Derivatives not designated as hedging contracts
|
|
Natural gas fixed price
|
(0.2) billion cubic feet
|
Natural gas basis
|
0.8 billion cubic feet
|
Fair Value of Derivative Contracts
|
||||||||||||||||||
Asset derivatives
|
Liability derivatives
|
|||||||||||||||||
June 30, 2010
|
December 31, 2009
|
June 30, 2010
|
December 31, 2009
|
|||||||||||||||
Balance sheet
location
|
Fair
value
|
Balance sheet
location
|
Fair
value
|
Balance Sheet
location
|
Fair
value
|
Balance sheet
Location
|
Fair
Value
|
|||||||||||
Derivatives designated as hedging contracts
|
||||||||||||||||||
Energy commodity derivative contracts
|
Current
|
$
|
36.0
|
Current
|
$
|
19.1
|
Current
|
$
|
(180.7)
|
Current
|
$
|
(270.8)
|
||||||
Non-current
|
84.8
|
Non-current
|
57.3
|
Non-current
|
(108.9)
|
Non-current
|
(241.5)
|
|||||||||||
Subtotal
|
120.8
|
76.4
|
(289.6)
|
(512.3)
|
||||||||||||||
Interest rate swap agreements
|
Non-current
|
459.6
|
Non-current
|
222.5
|
Non-current
|
(41.4)
|
Non-current
|
(218.6)
|
||||||||||
Total
|
580.4
|
298.9
|
(331.0)
|
(730.9)
|
||||||||||||||
Derivatives not designated as hedging contracts
|
||||||||||||||||||
Energy commodity derivative contracts
|
Current
|
8.5
|
Current
|
1.7
|
Current
|
(8.4)
|
Current
|
(1.2)
|
||||||||||
Non-current
|
-
|
Non-current
|
-
|
Non-current
|
-
|
Non-current
|
-
|
|||||||||||
Total
|
8.5
|
1.7
|
(8.4)
|
(1.2)
|
||||||||||||||
Total derivatives
|
$
|
588.9
|
$
|
300.6
|
$
|
(339.4)
|
$
|
(732.1)
|
Derivatives in
fair value
hedging
relationships
|
Location of
gain/(loss)
recognized in
income on
derivative
|
Amount of gain/(loss)
recognized in income on
derivative(a)
|
Hedged items in
fair value
hedging
relationships
|
Location of
gain/(loss)
recognized in
income on related
hedged item
|
Amount of gain/(loss)
recognized in income on
related hedged items(a)
|
|||||||||||||||
Three Months Ended
June 30,
|
Three Months Ended
June 30,
|
|||||||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||||||
Interest rate swap agreements
|
Interest, net – income/(expense)
|
$ | 348.6 | $ | (339.4 | ) |
Fixed rate debt
|
Interest, net – income/(expense)
|
$ | (348.6 | ) | $ | 339.4 | |||||||
Total
|
$ | 348.6 | $ | (339.4 | ) |
Total
|
$ | (348.6 | ) | $ | 339.4 | |||||||||
Six Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||
Interest rate swap agreements
|
Interest, net – income/(expense)
|
$ | 414.2 | $ | (469.8 | ) |
Fixed rate debt
|
Interest, net – income/(expense)
|
$ | (414.2 | ) | $ | 469.8 | |||||||
Total
|
$ | 414.2 | $ | (469.8 | ) |
Total
|
$ | (414.2 | ) | $ | 469.8 |
(a)
|
Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt which exactly offset each other as a result of no hedge ineffectiveness. Amounts do not reflect the impact on interest expense from the interest rate swap agreements under which we pay variable rate interest and receive fixed rate interest.
|
Derivatives in cash flow hedging relationships
|
Amount of gain/(loss) recognized in OCI on derivative
(effective portion)
|
Location of gain/(loss) reclassified from Accumulated OCI into income (effective portion)
|
Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)
|
Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
|
Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
|
||||||||||||||||||
Three Months Ended
June 30,
|
Three Months Ended
June 30,
|
Three Months Ended
June 30,
|
|||||||||||||||||||||
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
||||||||||||||||||
Energy commodity derivative contracts
|
$
|
143.1
|
$
|
(339.5)
|
Revenues-natural gas sales
|
$
|
1.7
|
$
|
4.8
|
Revenues-product sales and other
|
$
|
7.9
|
$
|
-
|
|||||||||
Revenues-product sales and other
|
(48.4)
|
(28.9)
|
|||||||||||||||||||||
Gas purchases and other costs of sales
|
7.2
|
(6.5)
|
Gas purchases and other costs of sales
|
(0.1)
|
-
|
||||||||||||||||||
Total
|
$
|
143.1
|
$
|
(339.5)
|
Total
|
$
|
(39.5)
|
$
|
(30.6)
|
Total
|
$
|
7.8
|
$
|
-
|
|||||||||
Six Months Ended
June 30,
|
Six Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||||||||
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
||||||||||||||||||
Energy commodity derivative contracts
|
$
|
167.7
|
$
|
(303.6)
|
Revenues-natural gas sales
|
$
|
1.7
|
$
|
6.5
|
Revenues-product sales and other
|
$
|
13.3
|
$
|
-
|
|||||||||
Revenues-product sales and other
|
(98.4)
|
(12.9)
|
|||||||||||||||||||||
Gas purchases and other costs of sales
|
9.7
|
(6.9)
|
Gas purchases and other costs of sales
|
0.8
|
-
|
||||||||||||||||||
Total
|
$
|
167.7
|
$
|
(303.6)
|
Total
|
$
|
(87.0)
|
$
|
(13.3)
|
Total
|
$
|
14.1
|
$
|
-
|
Asset position
|
||||
Interest rate swap agreements
|
$ | 459.6 | ||
Energy commodity derivative contracts
|
129.3 | |||
Gross exposure
|
588.9 | |||
Netting agreement impact
|
(93.6 | ) | ||
Net exposure
|
$ | 495.3 |
Credit ratings downgraded(a)
|
Incremental
obligations
|
Cumulative
obligations(b)
|
||||||
One notch to BBB-/Baa3
|
$
|
3.7
|
$
|
23.0
|
||||
Two notches to below BBB-/Baa3 (below investment grade)
|
$
|
90.8
|
$
|
113.8
|
(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 one notch downgrade to BBB-/Baa3 by one agency would not trigger the entire $3.7 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 June 30, 2010
|
||||||||||||||||
Energy commodity derivative contracts(a)
|
$ | 129.3 | $ | - | $ | 55.1 | $ | 74.2 | ||||||||
Interest rate swap agreements
|
$ | 459.6 | $ | - | $ | 459.6 | $ | - | ||||||||
As of December 31, 2009
|
||||||||||||||||
Energy commodity derivative contracts(a)
|
$ | 78.1 | $ | - | $ | 14.4 | $ | 63.7 | ||||||||
Interest rate swap agreements
|
$ | 222.5 | $ | - | $ | 222.5 | $ | - |
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 June 30, 2010
|
||||||||||||||||
Energy commodity derivative contracts(b)
|
$ | (298.0 | ) | $ | - | $ | (270.4 | ) | $ | (27.6 | ) | |||||
Interest rate swap agreements
|
$ | (41.4 | ) | $ | - | $ | (41.4 | ) | $ | - | ||||||
As of December 31, 2009
|
||||||||||||||||
Energy commodity derivative contracts(b)
|
$ | (513.5 | ) | $ | - | $ | (462.8 | ) | $ | (50.7 | ) | |||||
Interest rate swap agreements
|
$ | (218.6 | ) | $ | - | $ | (218.6 | ) | $ | - |
(a)
|
Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas basis swaps, West Texas Sour hedges, natural gas options, and West Texas Intermediate options.
|
(b)
|
Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas basis swaps, West Texas Sour hedges, and West Texas Intermediate options.
|
Significant unobservable inputs (Level 3)
|
||||||||||||||||
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Derivatives-net asset (liability)
|
||||||||||||||||
Beginning of Period
|
$ | 22.6 | $ | 53.4 | $ | 13.0 | $ | 44.1 | ||||||||
Realized and unrealized net gains and (losses)
|
18.1 | (28.1 | ) | 26.7 | (21.8 | ) | ||||||||||
Purchases and settlements
|
5.9 | (1.3 | ) | 6.9 | 1.7 | |||||||||||
Transfers in (out) of Level 3
|
- | - | - | - | ||||||||||||
End of Period
|
$ | 46.6 | $ | 24.0 | $ | 46.6 | $ | 24.0 | ||||||||
Change in unrealized net losses relating to contracts still
|
||||||||||||||||
held at end of period
|
$ | 19.2 | $ | (29.7 | ) | $ | 24.1 | $ | (39.5 | ) |
June 30, 2010
|
December 31, 2009
|
|||||||||||||||
Carrying
Value
|
Estimated
fair value
|
Carrying
value
|
Estimated
fair value
|
|||||||||||||
Total Debt
|
$ | 11,850.8 | $ | 12,678.9 | $ | 10,592.4 | $ | 11,265.7 |
|
▪
|
Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;
|
|
▪
|
Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;
|
|
▪
|
CO
2
—the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;
|
|
▪
|
Terminals—the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and
|
|
▪
|
Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Revenues
|
||||||||||||||||
Products Pipelines
|
||||||||||||||||
Revenues from external customers
|
$ | 226.3 | $ | 206.7 | $ | 433.8 | $ | 394.9 | ||||||||
Natural Gas Pipelines
|
||||||||||||||||
Revenues from external customers
|
1,029.7 | 860.7 | 2,266.4 | 1,912.4 | ||||||||||||
CO
2
|
||||||||||||||||
Revenues from external customers
|
314.6 | 258.2 | 636.4 | 487.1 | ||||||||||||
Terminals
|
||||||||||||||||
Revenues from external customers
|
320.3 | 263.7 | 624.1 | 531.4 | ||||||||||||
Intersegment revenues
|
0.2 | 0.3 | 0.5 | 0.5 | ||||||||||||
Kinder Morgan Canada
|
||||||||||||||||
Revenues from external customers
|
70.6 | 56.0 | 130.4 | 106.0 | ||||||||||||
Total segment revenues
|
1,961.7 | 1,645.6 | 4,091.6 | 3,432.3 | ||||||||||||
Less: Total intersegment revenues
|
(0.2 | ) | (0.3 | ) | (0.5 | ) | (0.5 | ) | ||||||||
Total consolidated revenues
|
$ | 1,961.5 | $ | 1,645.3 | $ | 4,091.1 | $ | 3,431.8 |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
Segment earnings before depreciation, depletion, amortization
and amortization of excess cost of equity investments(a)
|
||||||||||||||||
Products Pipelines(b)
|
$ | 165.2 | $ | 155.0 | $ | 171.6 | $ | 300.4 | ||||||||
Natural Gas Pipelines
|
185.0 | 162.1 | 405.6 | 362.9 | ||||||||||||
CO
2
|
249.4 | 202.7 | 502.6 | 370.1 | ||||||||||||
Terminals
|
165.5 | 142.9 | 316.0 | 277.6 | ||||||||||||
Kinder Morgan Canada
|
43.9 | 46.7 | 88.9 | 66.2 | ||||||||||||
Total segment earnings before DD&A
|
809.0 | 709.4 | 1,484.7 | 1,377.2 | ||||||||||||
Total segment depreciation, depletion and amortization
|
(223.2 | ) | (203.1 | ) | (450.5 | ) | (413.3 | ) | ||||||||
Total segment amortization of excess cost of investments
|
(1.5 | ) | (1.5 | ) | (2.9 | ) | (2.9 | ) | ||||||||
General and administrative expenses
|
(93.4 | ) | (72.6 | ) | (194.5 | ) | (155.1 | ) | ||||||||
Unallocable interest expense, net of interest income
|
(123.8 | ) | (101.3 | ) | (240.1 | ) | (205.9 | ) | ||||||||
Unallocable income tax expense
|
(2.0 | ) | (2.3 | ) | (4.2 | ) | (4.6 | ) | ||||||||
Total consolidated net income
|
$ | 365.1 | $ | 328.6 | $ | 592.5 | $ | 595.4 |
June 30,
2010
|
December 31,
2009
|
|||||||
Assets
|
||||||||
Products Pipelines
|
$ | 4,314.3 | $ | 4,299.0 | ||||
Natural Gas Pipelines
|
8,789.8 | 7,772.7 | ||||||
CO
2
|
2,195.3 | 2,224.5 | ||||||
Terminals
|
3,986.8 | 3,636.6 | ||||||
Kinder Morgan Canada
|
1,761.0 | 1,797.7 | ||||||
Total segment assets
|
21,047.2 | 19,730.5 | ||||||
Corporate assets(c)
|
781.1 | 531.7 | ||||||
Total consolidated assets
|
$ | 21,828.3 | $ | 20,262.2 |
(a)
|
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
|
(b)
|
Six month 2010 amount includes a $158.0 million increase in expense associated with rate case liability adjustments. Following the Federal Regulatory Energy Commission’s approval of a settlement agreement we reached with certain shippers, we made settlement payments totaling $206.3
million in June 2010. For more information on our rate case proceedings, see Note 10.
|
(c)
|
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.
|
June 30,
2010
|
December 31,
2009
|
|||||||
Derivatives – asset/(liability)
|
||||||||
Current assets
|
$ | 0.4 | $ | 4.3 | ||||
Noncurrent assets
|
$ | 22.4 | $ | 18.4 | ||||
Current liabilities
|
$ | (84.2 | ) | $ | (96.8 | ) | ||
Noncurrent liabilities
|
$ | (82.5 | ) | $ | (190.8 | ) |
|
SFPP
|
|
▪
|
FERC Docket Nos. OR92-8, et al. (West and East Line Rates)—Chevron protests of compliance filings pending with FERC and appeals pending at the D.C. Circuit;
|
|
▪
|
FERC Docket Nos. OR96-2, et al. (All SFPP Rates)—Chevron (as a successor-in-interest to Texaco) protests of compliance filings pending with FERC;
|
|
▪
|
FERC Docket No. OR02-4 (All SFPP Rates)—Chevron appeal of complaint dismissal pending at the D.C. Circuit;
|
|
▪
|
FERC Docket No. OR03-5 (West, East, North, and Oregon Line Rates)—Chevron exceptions to initial decision pending at FERC;
|
|
▪
|
FERC Docket No. OR07-4 (All SFPP Rates)—Chevron complaint held in abeyance;
|
|
▪
|
FERC Docket No. OR09-8 (consolidated) (2008 Index Increases)—Hearing regarding Chevron complaint held in abeyance pending settlement discussions;
|
|
▪
|
FERC Docket No. IS98-1 (Sepulveda Line Rates)—Chevron protests to compliance filing pending at FERC;
|
|
▪
|
FERC Docket No. IS05-230 (North Line Rates)—Chevron exceptions to initial decision pending at FERC;
|
|
▪
|
FERC Docket No. IS07-116 (Sepulveda Line Rates)—Chevron protest subject to resolution of IS98-1 proceeding;
|
|
▪
|
FERC Docket No. IS08-137 (West and East Line Rates)—Chevron protest subject to resolution of the OR92-8/OR96-2 proceeding;
|
|
▪
|
FERC Docket No. IS08-302 (2008 Index Rate Increases)—Chevron protest subject to the resolution of proceedings regarding the West, North and Sepulveda Lines;
|
|
▪
|
FERC Docket No. IS09-375 (2009 Index Rate Increases)—Chevron protest subject to resolution of proceedings regarding the North, West and Sepulveda Lines;
|
|
▪
|
FERC Docket No. IS08-390 (West Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Status: Exceptions to initial decision pending at FERC;
|
|
▪
|
FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero, Chevron, Western Refining, and Southwest Airlines—Status: Hearing stage.
|
|
▪
|
FERC Docket No. OR07-3 (2005-2006 North Line Index Rate Increases)—Protestants: BP, ExxonMobil, Tesoro, Valero Marketing, Chevron—Defendant: SFPP—Status: Petition for review at D.C. Circuit denied, mandate issued.
|
|
▪
|
FERC Docket No. OR09-16 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: Tesoro—Defendant: SFPP—Status: Dismissed at FERC; no appeal taken; and
|
|
▪
|
FERC Docket No. OR09-17 (Most SFPP Rates) (not consolidated)—Complainants: Tesoro—Defendant: SFPP—Status: Dismissed at FERC; no appeal taken.
|
|
Calnev
|
|
▪
|
FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status: Complaint amendments pending before FERC;
|
|
▪
|
FERC Docket No. IS09-377 (2009 Index Rate Increases)
—
Protestants: BP, Chevron, and Tesoro—Status: Requests for rehearing of FERC dismissal pending before FERC;
|
|
▪
|
FERC Docket Nos. OR09-11/OR09-14 (not consolidated) (2007 and 2008 Page 700 Audit Request)—Complainants: BP/Tesoro—Status: BP petition for review at D.C. Circuit dismissed, mandate issued;
|
|
▪
|
FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev Rates)—Complainants: Tesoro/BP—Status: Complaints pending at FERC;
|
|
▪
|
FERC Docket Nos. OR09-18/OR09-22 (not consolidated) (2009 Index Increases)—Complainants: Tesoro/BP
—
Status: BP petition for review at D.C. Circuit dismissed, mandate issued.
|
|
Trailblazer Pipeline Company LLC
|
Three Months Ended
June 30,
|
Earnings
|
|||||||||||||||
2010
|
2009
|
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)
|
$ | 165.2 | $ | 155.0 | $ | 10.2 | 7 | % | ||||||||
Natural Gas Pipelines(c)
|
185.0 | 162.1 | 22.9 | 14 | % | |||||||||||
CO
2
(d)
|
249.4 | 202.7 | 46.7 | 23 | % | |||||||||||
Terminals(e)
|
165.5 | 142.9 | 22.6 | 16 | % | |||||||||||
Kinder Morgan Canada(f)
|
43.9 | 46.7 | (2.8 | ) | (6 | ) % | ||||||||||
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments |
809.0 | 709.4 | 99.6 | 14 | % | |||||||||||
Depreciation, depletion and amortization expense
|
(223.2 | ) | (203.1 | ) | (20.1 | ) | (10 | ) % | ||||||||
Amortization of excess cost of equity investments
|
(1.5 | ) | (1.5 | ) | - | - | ||||||||||
General and administrative expense(g)
|
(93.4 | ) | (72.6 | ) | (20.8 | ) | (29 | ) % | ||||||||
Unallocable interest expense, net of interest income(h)
|
(123.8 | ) | (101.3 | ) | (22.5 | ) | (22 | ) % | ||||||||
Unallocable income tax expense
|
(2.0 | ) | (2.3 | ) | 0.3 | 13 | % | |||||||||
Net income
|
365.1 | 328.6 | 36.5 | 11 | % | |||||||||||
Net income attributable to noncontrolling interests(i)
|
(3.9 | ) | (4.8 | ) | 0.9 | 19 | % | |||||||||
Net income attributable to Kinder Morgan Energy Partners, L.P.
|
$ | 361.2 | $ | 323.8 | $ | 37.4 | 12 | % |
Six Months Ended
June 30,
|
Earnings
|
|||||||||||||||
2010
|
2009
|
increase/(decrease)
|
||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)
|
||||||||||||||||
Products Pipelines(j)
|
$ | 171.6 | $ | 300.4 | $ | (128.8 | ) | (43 | ) % | |||||||
Natural Gas Pipelines(k)
|
405.6 | 362.9 | 42.7 | 12 | % | |||||||||||
CO
2
(l)
|
502.6 | 370.1 | 132.5 | 36 | % | |||||||||||
Terminals(m)
|
316.0 | 277.6 | 38.4 | 14 | % | |||||||||||
Kinder Morgan Canada(n)
|
88.9 | 66.2 | 22.7 | 34 | % | |||||||||||
Segment earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments |
1,484.7 | 1,377.2 | 107.5 | 8 | % | |||||||||||
Depreciation, depletion and amortization expense
|
(450.5 | ) | (413.3 | ) | (37.2 | ) | (9 | ) % | ||||||||
Amortization of excess cost of equity investments
|
(2.9 | ) | (2.9 | ) | - | - | ||||||||||
General and administrative expense(o)
|
(194.5 | ) | (155.1 | ) | (39.4 | ) | (25 | ) % | ||||||||
Unallocable interest expense, net of interest income(p)
|
(240.1 | ) | (205.9 | ) | (34.2 | ) | (17 | ) % | ||||||||
Unallocable income tax expense
|
(4.2 | ) | (4.6 | ) | 0.4 | 9 | % | |||||||||
Net income
|
592.5 | 595.4 | (2.9 | ) | - | |||||||||||
Net income attributable to noncontrolling interests(q)
|
(6.0 | ) | (7.7 | ) | 1.7 | 22 | % | |||||||||
Net income attributable to Kinder Morgan Energy Partners, L.P.
|
$ | 586.5 | $ | 587.7 | $ | (1.2 | ) | - |
(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)
|
2010 and 2009 amounts include a decrease in income of $0.4 million and an increase in income of $1.0 million, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions. 2010 amount also includes a $15.5 million decrease in income associated with combined property environmental expenses and disposal losses related to the retirement of our Gaffey Street, California products terminal facility. 2009 amount also includes a $3.8 million increase in expense associated with environmental liability adjustments.
|
(c)
|
2010 amount includes a $0.1 million unrealized loss on derivative contracts used to hedge forecasted natural gas sales. 2009 amount includes a $2.5 million decrease in income resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas.
|
(d)
|
2010 amount includes a $7.9 million unrealized gain on derivative contracts used to hedge forecasted crude oil sales.
|
(e)
|
2010 amount includes a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal, and a $0.2 million increase in expense related to storm and flood clean-up and repair activities. 2009 amount includes a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments.
|
(f)
|
2009 amount includes a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals made by the Express pipeline system.
|
(g)
|
Includes unallocated litigation and environmental expenses. 2010 and 2009 amounts include (i) increases in expense of $1.3 million and $1.4 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) an increase in expense of $0.1 million and a decrease in expense of $0.9 million, respectively, related to capitalized overhead costs associated with the 2008 hurricane season. 2010 amount also includes a $1.0 million increase in expense for certain asset and business acquisition costs.
|
(h)
|
2010 and 2009 amounts include increases in imputed interest expense of $0.2 million and $0.3 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
|
(i)
|
2010 amount includes a $0.1 million decrease in net income attributable to our noncontrolling interests, related to the effect from all of the three month 2010 items previously disclosed in these footnotes.
|
(j)
|
2010 and 2009 amounts include increases in income of $0.1 million and $0.4 million, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions. 2010 amount also includes a $158.0 million expense associated with rate case liability adjustments, and a $15.5 million decrease in income associated with combined property environmental expenses and disposal losses related to the retirement of our Gaffey Street, California products terminal facility. 2009 amount also includes a $3.8 million increase in expense associated with environmental liability adjustments. With respect to our 2010 rate case liability adjustments, following the Federal Regulatory Energy Commission’s approval of a settlement agreement we reached with certain shippers, we made settlement payments totaling $206.3
million in June 2010. For more information on our rate case proceedings, see Note 10 to our consolidated financial statements included elsewhere in this report.
|
(k)
|
2010 amount includes a $0.8 million unrealized gain on derivative contracts used to hedge forecasted natural gas sales, and a $0.4 million increase in income from certain measurement period adjustments related to our October 1, 2009 natural gas treating business acquisition. 2009 amount includes a $3.8 million decrease in income resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas.
|
(l)
|
2010 amount includes a $13.3 million unrealized gain on derivative contracts used to hedge forecasted crude oil sales.
|
(m)
|
2010 amount includes a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal, and a $0.6 million increase in expense related to storm and flood clean-up and repair activities. 2009 amount includes a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments.
|
(n)
|
2009 amount includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to the carrying amount of Trans Mountain pipeline system’s previously established deferred tax liability, and a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals made by the Express pipeline system.
|
(o)
|
Includes unallocated litigation and environmental expenses. 2010 and 2009 amounts include (i) increases in expense of $2.7 million and $2.8 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); (ii) increases in expense of $2.4 million and $0.1 million, respectively, for certain asset and business acquisition costs; and (iii) decreases in expense of $0.2 million and $1.5 million, respectively, related to capitalized overhead costs associated with the 2008 hurricane season. 2010 amount also includes a $1.6 million increase in legal expense associated with certain items such as legal settlements and pipeline failures.
|
(p)
|
2010 and 2009 amounts include increases in imputed interest expense of $0.6 million and $0.8 million, respectively, related to our January 1, 2007 Cochin Pipeline acquisition.
|
(q)
|
2010 and 2009 amounts include decreases of $2.4 million and $0.2 million, respectively, in net income attributable to our noncontrolling interests, related to all of the six month 2010 and 2009 items previously disclosed in these footnotes.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions, except operating statistics)
|
||||||||||||||||
Revenues
|
$ | 226.3 | $ | 206.7 | $ | 433.8 | $ | 394.9 | ||||||||
Operating expenses(a)
|
(65.0 | ) | (60.0 | ) | (273.9 | ) | (109.0 | ) | ||||||||
Other expense(b)
|
(3.9 | ) | - | (3.9 | ) | - | ||||||||||
Earnings from equity investments
|
8.8 | 8.0 | 14.6 | 13.4 | ||||||||||||
Interest income and Other, net-income(c)
|
1.3 | 3.5 | 3.9 | 6.3 | ||||||||||||
Income tax expense
|
(2.3 | ) | (3.2 | ) | (2.9 | ) | (5.2 | ) | ||||||||
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments |
$ | 165.2 | $ | 155.0 | $ | 171.6 | $ | 300.4 | ||||||||
Gasoline (MMBbl)(d)
|
103.4 | 104.2 | 197.2 | 199.8 | ||||||||||||
Diesel fuel (MMBbl)
|
38.3 | 36.5 | 71.1 | 72.0 | ||||||||||||
Jet fuel (MMBbl)
|
26.2 | 28.1 | 51.0 | 54.9 | ||||||||||||
Total refined product volumes (MMBbl)
|
167.9 | 168.8 | 319.3 | 326.7 | ||||||||||||
Natural gas liquids (MMBbl)
|
5.7 | 7.3 | 11.6 | 12.2 | ||||||||||||
Total delivery volumes (MMBbl)(e)
|
173.6 | 176.1 | 330.9 | 338.9 | ||||||||||||
Ethanol (MMBbl)(f)
|
7.6 | 5.5 | 14.8 | 10.6 |
(a)
|
Three and six month 2010 amounts include an $11.6 million increase in property environmental expenses associated with the retirement of our Gaffey Street, California products terminal facility. Six month 2010 amount also includes a $158.0 million increase in expense associated with rate case liability adjustments. Three and six month 2009 amounts include a $3.8 million increase in expense associated with environmental liability adjustments.
|
(b)
|
Three and six month 2010 amounts represent property disposal losses related to the retirement of our Gaffey Street, California products terminal facility.
|
(c)
|
Three and six month 2010 amounts include a $0.4 million decrease in income and a $0.1 million increase in income, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions. Three and six month 2009 amounts include increases in income of $1.0 million and $0.4 million, respectively, resulting from unrealized foreign currency gains and losses on long-term debt transactions.
|
(d)
|
Volumes include ethanol pipeline volumes.
|
(e)
|
Includes Pacific, Plantation, Calnev, Central Florida, Cochin and Cypress pipeline volumes.
|
(f)
|
Represents total ethanol volumes, including ethanol pipeline volumes.
|
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Pacific operations
|
$ | 13.4 | 20 | % | $ | 14.9 | 15 | % | ||||||||
Southeast Terminals
|
7.6 | 56 | % | 6.0 | 30 | % | ||||||||||
Transmix operations
|
4.2 | 60 | % | 1.3 | 13 | % | ||||||||||
West Coast Terminals
|
3.5 | 22 | % | 2.7 | 12 | % | ||||||||||
Central Florida Pipeline
|
2.9 | 21 | % | 0.5 | 3 | % | ||||||||||
Cochin Pipeline
|
(9.5 | ) | (68 | ) % | (7.7 | ) | (45 | ) % | ||||||||
All others (including intrasegment eliminations)
|
1.2 | 5 | % | 1.9 | 8 | % | ||||||||||
Total Products Pipelines
|
$ | 23.3 | 15 | % | $ | 19.6 | 9 | % |
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Pacific operations
|
$ | 23.1 | 18 | % | $ | 25.6 | 14 | % | ||||||||
Southeast Terminals
|
12.2 | 49 | % | 10.8 | 29 | % | ||||||||||
West Coast Terminals
|
4.7 | 14 | % | 3.8 | 8 | % | ||||||||||
Transmix operations
|
4.4 | 32 | % | 1.5 | 8 | % | ||||||||||
Central Florida Pipeline
|
4.1 | 16 | % | 1.5 | 5 | % | ||||||||||
Cochin Pipeline
|
(12.1 | ) | (48 | ) % | (7.9 | ) | (29 | ) % | ||||||||
All others (including intrasegment eliminations)
|
4.8 | 10 | % | 3.6 | 8 | % | ||||||||||
Total Products Pipelines
|
$ | 41.2 | 14 | % | $ | 38.9 | 10 | % |
|
▪
|
increases of $13.4 million (20%) and $23.1 million (18%), respectively, from our Pacific operations—driven by (i) increased mainline delivery revenues, due to higher average tariffs partly offset by decreases in mainline delivery
|
|
▪
|
increases of $7.6 million (56%) and $12.2 million (49%), respectively, from our Southeast terminal operations—related largely to higher revenues attributable to both increased ethanol throughput and higher product inventory sales at higher prices;
|
|
▪
|
increases of $4.2 million (60%) and $4.4 million (32%), respectively, from our Transmix processing operations—due largely to incremental liquids product inventory gains of $5.1 million, recognized pursuant to a periodic physical inventory completed in the second quarter of 2010;
|
|
▪
|
increases of $3.5 million (22%) and $4.7 million (14%), respectively, from our West Coast terminal operations—driven by higher warehousing revenues at our combined Carson/Los Angeles Harbor terminal system, incremental biodiesel revenues from our liquids facilities located in Portland, Oregon, and incremental earnings contributions from the terminals’ Portland, Oregon Airport pipeline, which was acquired on July 31, 2009;
|
|
▪
|
increases of $2.9 million (21%) and $4.1 million (16%), respectively, from our Central Florida Pipeline—driven by incremental product inventory gains, and for the comparable six month periods, by higher ethanol revenues and higher refined products delivery revenues;
|
|
▪
|
decreases of $9.5 million (68%) and $12.1 million (48%), respectively, from our Cochin pipeline system—attributable to a 51% decrease in total pipeline throughput volumes quarter-to-quarter, and for the comparable six month periods, attributable to both higher operating expenses and lower other non-operating income. The decreases in earnings from higher operating expenses and lower non-operating income were primarily related to favorable settlements reached in the first quarter of 2009 with the seller of the remaining approximate 50.2% interest in the Cochin pipeline system that we purchased on January 1, 2007.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions, except operating statistics)
|
||||||||||||||||
Revenues(a)
|
$ | 1,029.7 | $ | 860.7 | $ | 2,266.4 | $ | 1,912.4 | ||||||||
Operating expenses(b)
|
(884.8 | ) | (739.3 | ) | (1,936.3 | ) | (1,629.8 | ) | ||||||||
Earnings from equity investments
|
40.1 | 29.4 | 73.9 | 56.0 | ||||||||||||
Interest income and Other, net-income
|
0.1 | 12.6 | 2.3 | 27.3 | ||||||||||||
Income tax expense
|
(0.1 | ) | (1.3 | ) | (0.7 | ) | (3.0 | ) | ||||||||
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments |
$ | 185.0 | $ | 162.1 | $ | 405.6 | $ | 362.9 | ||||||||
Natural gas transport volumes (Bcf)(c)
|
634.6 | 541.8 | 1,268.3 | 1,050.3 | ||||||||||||
Natural gas sales volumes (Bcf)(d)
|
199.0 | 198.1 | 388.0 | 401.8 |
(a)
|
Six 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)
|
Three and six month 2010 amounts include a $0.1 million unrealized loss (from an increase in natural gas purchase costs) and a $0.8 million unrealized gain (from a decrease in natural gas purchase costs), respectively, on derivative contracts used to hedge forecasted natural gas sales. Three and six month 2009 amounts include decreases in income (from net increases in natural gas purchase costs) of $2.5 million and $3.8 million, respectively, resulting from unrealized mark to market gains and losses due to the discontinuance of hedge accounting at Casper Douglas. Beginning in the second quarter of 2008, our Casper and Douglas gas processing operations discontinued hedge accounting, and the last of the related derivative contracts expired in December 2009.
|
(c)
|
Includes Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC and Texas intrastate natural gas pipeline group pipeline volumes.
|
(d)
|
Represents Texas intrastate natural gas pipeline group volumes.
|
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Kinder Morgan Natural Gas Treating
|
$ | 10.6 | n/a | $ | 15.3 | n/a | ||||||||||
Midcontinent Express Pipeline
|
6.7 | 957 | % | - | - | |||||||||||
Texas Intrastate Natural Gas Pipeline Group
|
2.9 | 4 | % | 132.9 | 17 | % | ||||||||||
Kinder Morgan Louisiana Pipeline
|
2.8 | 28 | % | 17.0 | n/a | |||||||||||
KinderHawk Field Services
|
1.7 | n/a | - | - | ||||||||||||
Rockies Express Pipeline
|
1.6 | 7 | % | - | - | |||||||||||
Kinder Morgan Interstate Gas Transmission
|
(7.5 | ) | (22 | ) % | (4.2 | ) | (9 | ) % | ||||||||
All others
|
1.7 | 5 | % | 8.0 | 18 | % | ||||||||||
Total Natural Gas Pipelines
|
$ | 20.5 | 12 | % | $ | 169.0 | 20 | % |
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Kinder Morgan Natural Gas Treating
|
$ | 21.1 | n/a | $ | 30.4 | n/a | ||||||||||
Midcontinent Express Pipeline
|
12.1 | 1736 | % | - | - | |||||||||||
Kinder Morgan Louisiana Pipeline
|
8.1 | 43 | % | 34.0 | n/a | |||||||||||
Rockies Express Pipeline
|
2.2 | 5 | % | - | - | |||||||||||
KinderHawk Field Services
|
1.7 | n/a | - | - | ||||||||||||
Kinder Morgan Interstate Gas Transmission
|
(6.9 | ) | (11 | ) % | (5.8 | ) | (7 | ) % | ||||||||
Texas Intrastate Natural Gas Pipeline Group
|
(6.1 | ) | (4 | ) % | 274.2 | 16 | % | |||||||||
All others
|
5.5 | 8 | % | 20.9 | 23 | % | ||||||||||
Intrasegment eliminations
|
- | - | (0.1 | ) | (18 | ) % | ||||||||||
Total Natural Gas Pipelines
|
$ | 37.7 | 10 | % | $ | 353.6 | 18 | % |
|
▪
|
an increase of $2.9 million (4%) and a decrease of $6.1 million (4%), respectively, from our Texas intrastate natural gas pipeline group. For the comparable three month periods, the increase in earnings was driven primarily by higher margins from proprietary storage activities and natural gas processing activities, and partly offset by lower margins from natural gas sales activities. For the comparable six month periods, the overall decrease in earnings was primarily impacted by lower natural gas sales volumes and margins, lower margins from proprietary storage activities, and lower interest income due to a one-time natural gas loan to a single customer in 2009. The decrease in earnings compared to the first half of 2009 was partially offset by higher natural gas processing margins;
|
|
▪
|
increases of $2.8 million (28%) and $8.1 million (43%), respectively, from our fully-owned Kinder Morgan Louisiana natural gas pipeline system. Our Kinder Morgan Louisiana pipeline system commenced limited natural gas transportation service in April 2009, and construction was fully completed and transportation service on the system’s remaining portions began in full on June 21, 2009. The overall increases in earnings included increases of $13.2 million and $26.4 million, respectively, in system operating income (revenues less operating expenses), due mainly to incremental transportation service, and decreases of $10.4 million and $18.3 million, respectively, in non-operating other income (primarily consisting of higher non-cash allowances for capital funds used during construction in the 2009 time periods);
|
|
▪
|
increases of $1.7 million and $1.7 million, respectively, due to incremental second quarter 2010 equity earnings from our 50%-owned KinderHawk Field Services LLC. We acquired our 50% ownership interest on May 21, 2010, and the joint venture’s operations include natural gas gathering and treating in the Haynesville shale gas formation located in northwest Louisiana;
|
|
▪
|
increases of $1.6 million (7%) and $2.2 million (5%), respectively, from our 50%-owned Rockies Express pipeline system—largely attributable to the completion and start-up of the Rockies Express-East pipeline segment, the third and final phase of the Rockies Express system. It began initial pipeline service on June 29, 2009, and began full operations on November 12, 2009.
|
|
▪
|
decreases of $7.5 million (22%) and $6.9 million (11%), respectively, from our Kinder Morgan Interstate Gas Transmission pipeline system—due largely to lower earnings from short-term natural gas balancing services (those services that offer shippers the option to store or withdraw natural gas as needed in order to manage overall gas supply), and lower volumes and prices for net fuel recoveries.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions, except operating statistics)
|
||||||||||||||||
Revenues(a)
|
$ | 314.6 | $ | 258.2 | $ | 636.4 | $ | 487.1 | ||||||||
Operating expenses
|
(72.6 | ) | (59.3 | ) | (151.7 | ) | (125.9 | ) | ||||||||
Earnings from equity investments
|
6.5 | 5.1 | 13.0 | 10.9 | ||||||||||||
Interest income and Other, net-income
|
1.9 | - | 1.9 | - | ||||||||||||
Income tax benefit (expense)
|
(1.0 | ) | (1.3 | ) | 3.0 | (2.0 | ) | |||||||||
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments |
$ | 249.4 | $ | 202.7 | $ | 502.6 | $ | 370.1 | ||||||||
Carbon dioxide delivery volumes (Bcf)(b)
|
191.6 | 188.7 | 382.6 | 401.4 | ||||||||||||
SACROC oil production (gross)(MBbl/d)(c)
|
29.1 | 31.1 | 29.5 | 30.6 | ||||||||||||
SACROC oil production (net)(MBbl/d)(d)
|
24.2 | 25.9 | 24.6 | 25.5 | ||||||||||||
Yates oil production (gross)(MBbl/d)(c)
|
24.3 | 26.8 | 24.9 | 26.6 | ||||||||||||
Yates oil production (net)(MBbl/d)(d)
|
10.8 | 11.9 | 11.1 | 11.8 | ||||||||||||
Natural gas liquids sales volumes (net)(MBbl/d)(d)
|
10.1 | 9.6 | 9.9 | 9.2 | ||||||||||||
Realized weighted average oil price per Bbl(e)(f)
|
$ | 59.58 | $ | 49.47 | $ | 60.05 | $ | 46.71 | ||||||||
Realized weighted average natural gas liquids price per Bbl(f)(g)
|
$ | 48.67 | $ | 34.02 | $ | 51.78 | $ | 31.20 |
(a)
|
Three and six month 2010 amounts include unrealized gains (from increases in revenues) of $7.9 million and $13.3 million, respectively, on derivative contracts used to hedge forecasted crude oil sales.
|
(b)
|
Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.
|
(c)
|
Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit and an approximately 50% working interest in the Yates unit.
|
(d)
|
Net to us, after royalties and outside working interests.
|
(e)
|
Includes all of our crude oil production properties.
|
(f)
|
Hedge gains/losses for crude oil and natural gas liquids are included with crude oil.
|
(g)
|
Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.
|
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Oil and Gas Producing Activities
|
$ | 21.9 | 14 | % | $ | 37.5 | 18 | % | ||||||||
Sales and Transportation Activities
|
16.9 | 35 | % | 15.8 | 27 | % | ||||||||||
Intrasegment eliminations
|
- | - | (4.8 | ) | (52 | ) % | ||||||||||
Total CO
2
|
$ | 38.8 | 19 | % | $ | 48.5 | 19 | % |
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Oil and Gas Producing Activities
|
$ | 95.3 | 37 | % | $ | 119.4 | 31 | % | ||||||||
Sales and Transportation Activities
|
23.9 | 22 | % | 19.6 | 15 | % | ||||||||||
Intrasegment eliminations
|
- | - | (3.0 | ) | (13 | ) % | ||||||||||
Total CO
2
|
$ | 119.2 | 32 | % | $ | 136.0 | 28 | % |
|
▪
|
increases of $34.8 million (17%) and $113.8 million (31%), respectively, in combined crude oil and natural gas plant products sales revenues, due largely to increases of 20% and 29%, respectively, in our realized weighted average price per barrel of crude oil, and increases of 43% and 66%, respectively, in our realized weighted average price per barrel of natural gas liquids. We also benefitted from period-to-period increases in natural gas liquids sales volumes. However, increases in crude oil revenues due to higher prices were somewhat offset by decreases in crude oil production volumes of 7% in the second quarter of 2010 and 4% in the first six months of 2010, when compared to the same periods a year ago;
|
|
▪
|
increases of $2.7 million (44%) and $5.6 million (47%), respectively, in other combined revenues, including natural gas sales, net profit interests and other service revenues. The quarterly increase was driven by higher natural gas sales revenues in 2010, and for the comparable six month periods, the increase was driven by higher net profit interests revenues in 2010 (from our interest in the Snyder, Texas natural gas processing plant); and
|
|
▪
|
decreases of $17.6 million (32%) and $26.2 million (21%), respectively, due to higher combined operating expenses. The overall increases in expenses were driven by (i) increases of $11.5 million (177%) and $12.3 million (361%), respectively, in tax expenses, other than income tax expenses, due primarily to a $15.4 million reduction in severance tax expense in the second quarter of 2009 due to prior year overpayments; and (ii) increases of $6.3 million (14%) and $9.6 million (11%), respectively, in operating and maintenance expenses, due largely to increased natural gas processing volumes.
|
|
▪
|
increases of $15.5 million (41%) and $20.8 million (25%), respectively, in carbon dioxide sales revenues. The period-to-period increases in sales revenues were primarily price related, and partly volume related. The segment’s average price received for all carbon dioxide sales in the second quarter and first six months of 2010 increased 36% and 23%, respectively, and overall carbon dioxide sales volumes increased 4% and 1%, respectively, when compared to the same prior year periods; and
|
|
▪
|
increases of $1.4 million (27%) and $2.1 million (19%), respectively, due to higher equity earnings from our 50% ownership interest in the Cortez Pipeline Company. The increase reflects higher net income earned by Cortez in 2010, chiefly due to lower depreciation expense resulting from a lower depreciable pipeline property base relative to 2009.
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
||||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||||
(In millions, except operating statistics)
|
|||||||||||||||
Revenues
|
$
|
320.5
|
$
|
264.0
|
$
|
624.6
|
$
|
531.9
|
|||||||
Operating expenses(a)
|
(160.7)
|
(123.9)
|
(316.6)
|
(257.5)
|
|||||||||||
Other income(b)
|
9.2
|
2.7
|
10.5
|
3.6
|
|||||||||||
Earnings from equity investments
|
0.4
|
-
|
0.6
|
0.1
|
|||||||||||
Interest income and Other, net-income (expense)
|
(0.5)
|
1.2
|
0.4
|
1.1
|
|||||||||||
Income tax expense
|
(3.4)
|
(1.1)
|
(3.5)
|
(1.6)
|
|||||||||||
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments |
$
|
165.5
|
$
|
142.9
|
$
|
316.0
|
$
|
277.6
|
|||||||
Bulk transload tonnage (MMtons)(c)
|
25.2
|
19.8
|
46.6
|
39.1
|
|||||||||||
Ethanol (MMBbl)
|
14.6
|
8.0
|
30.0
|
16.6
|
|||||||||||
Liquids leasable capacity (MMBbl)
|
58.2
|
55.1
|
58.2
|
55.1
|
|||||||||||
Liquids utilization %
|
95.8
|
%
|
96.9
|
%
|
95.8
|
%
|
96.9
|
%
|
(a)
|
Three and six month 2010 amounts include increases in expense of $0.2 million and $0.6 million, respectively, related to storm and flood clean-up and repair activities. Three and six month 2009 amounts include a $0.5 million decrease in expense associated with legal liability adjustments related to a litigation matter involving our Staten Island liquids terminal, and a $0.1 million increase in expense associated with environmental liability adjustments.
|
(b)
|
Three and six month 2010 amounts include a $6.7 million casualty indemnification gain related to a 2008 fire at our Pasadena, Texas liquids terminal.
|
(c)
|
Volumes for acquired terminals are included for all periods.
|
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Mid-River
|
$ | 3.3 | 90 | % | $ | 10.1 | 87 | % | ||||||||
Southeast
|
2.9 | 29 | % | 5.1 | 23 | % | ||||||||||
Ohio Valley
|
2.9 | 68 | % | 4.9 | 36 | % | ||||||||||
Gulf Coast
|
2.4 | 7 | % | 3.5 | 8 | % | ||||||||||
West
|
2.3 | 19 | % | 8.6 | 44 | % | ||||||||||
Texas Petcoke
|
2.0 | 12 | % | 4.4 | 13 | % | ||||||||||
Lower River (Louisiana)
|
(3.1 | ) | (22 | ) % | 2.7 | 12 | % | |||||||||
All others (including intrasegment eliminations and
unallocated income tax expenses) |
(4.5 | ) | (10 | ) % | 0.3 | - | ||||||||||
Total Terminals
|
$ | 8.2 | 6 | % | $ | 39.6 | 15 | % |
EBDA
increase/(decrease)
|
Revenues
increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
West
|
$ | 10.5 | 52 | % | $ | 21.7 | 58 | % | ||||||||
Mid-River
|
5.7 | 76 | % | 15.6 | 63 | % | ||||||||||
Southeast
|
4.5 | 23 | % | 8.6 | 20 | % | ||||||||||
Gulf Coast
|
3.9 | 6 | % | 6.4 | 7 | % | ||||||||||
Ohio Valley
|
3.0 | 39 | % | 6.5 | 25 | % | ||||||||||
Texas Petcoke
|
(3.4 | ) | (10 | ) % | (0.3 | ) | - | |||||||||
Lower River (Louisiana)
|
(3.0 | ) | (12 | ) % | 3.1 | 7 | % | |||||||||
All others (including intrasegment eliminations and
unallocated income tax expenses) |
(3.3 | ) | (4 | ) % | (0.6 | ) | - | |||||||||
Total Terminals
|
$ | 17.9 | 6 | % | $ | 61.0 | 11 | % |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions, except operating statistics)
|
||||||||||||||||
Revenues
|
$ | 70.6 | $ | 56.0 | $ | 130.4 | $ | 106.0 | ||||||||
Operating expenses
|
(23.7 | ) | (18.1 | ) | (43.2 | ) | (33.3 | ) | ||||||||
Earnings from equity investments
|
(0.6 | ) | (0.6 | ) | (0.2 | ) | (0.3 | ) | ||||||||
Interest income and Other, net-income
|
1.8 | 8.2 | 7.6 | 8.9 | ||||||||||||
Income tax benefit (expense)(a)
|
(4.2 | ) | 1.2 | (5.7 | ) | (15.1 | ) | |||||||||
Earnings before depreciation, depletion and amortization expense
and amortization of excess cost of equity investments |
$ | 43.9 | $ | 46.7 | $ | 88.9 | $ | 66.2 | ||||||||
Transport volumes (MMBbl)(b)
|
28.3 | 24.3 | 52.1 | 46.9 |
(a)
|
Three and six month 2009 amounts include a $3.7 million decrease in expense due to a certain non-cash accounting change related to book tax accruals made by the Express pipeline system. Six month 2009 amount also includes a $14.9 million increase in expense primarily due to certain non-cash regulatory accounting adjustments to Trans Mountain’s carrying amount of the previously established deferred tax liability.
|
(b)
|
Represents Trans Mountain pipeline system volumes.
|
EBDA
increase/(decrease)
|
Revenues
Increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Express Pipeline
|
$ | 1.2 | 89 | % | $ | - | - | |||||||||
Trans Mountain and Jet Fuel Pipelines
|
(0.3 | ) | (1 | ) % | 14.6 | 26 | % | |||||||||
Total Kinder Morgan Canada
|
$ | 0.9 | 2 | % | $ | 14.6 | 26 | % |
EBDA
Increase/(decrease)
|
Revenues
Increase/(decrease)
|
|||||||||||||||
(In millions, except percentages)
|
||||||||||||||||
Trans Mountain and Jet Fuel Pipelines
|
$ | 10.2 | 14 | % | $ | 24.4 | 23 | % | ||||||||
Express Pipeline
|
1.3 | 27 | % | - | - | |||||||||||
Total Kinder Morgan Canada
|
$ | 11.5 | 15 | % | $ | 24.4 | 23 | % |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions)
|
||||||||||||||||
General and administrative expenses(a)
|
$ | 93.4 | $ | 72.6 | $ | 194.5 | $ | 155.1 | ||||||||
Unallocable interest expense, net of interest income(b)
|
$ | 123.8 | $ | 101.3 | $ | 240.1 | $ | 205.9 | ||||||||
Unallocable income tax expense
|
$ | 2.0 | $ | 2.3 | $ | 4.2 | $ | 4.6 | ||||||||
Net income attributable to noncontrolling interests(c)
|
$ | 3.9 | $ | 4.8 | $ | 6.0 | $ | 7.7 |
(a)
|
Includes such items as salaries and employee-related expenses, payroll taxes, insurance, office supplies and rentals, unallocated litigation and environmental expenses, and shared corporate services. Three and six month 2010 amounts include (i) increases in expense of $1.3 million and $2.7 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); (ii) increases in expense of $1.0 million and $2.4 million, respectively, for certain asset and business acquisition costs; and (iii) an increase in expense of $0.1 million and a decrease in expense of $0.2 million, respectively, related to capitalized overhead costs associated with the 2008 hurricane season. Six month 2010 amount also includes an increase in legal expense of $1.6 million associated with certain items such as legal settlements and pipeline failures. Three and six month 2009 amounts include (i) increases in expense of $1.4 million and $2.8 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) decreases in expense of $0.9 million and $1.5 million, respectively, from capitalized overhead costs associated with the 2008 hurricane season. Six month 2009 amount also includes an increase in expense of $0.1 million for certain asset and business acquisition costs that were capitalized under prior accounting standards.
|
(b)
|
Three and six month 2010 amounts include increases in imputed interest expense of $0.2 million and $0.6 million, respectively, and three and six month 2009 amounts include increases in imputed interest expense of $0.3 million and $0.8 million, respectively, all related to our January 1, 2007 Cochin Pipeline acquisition.
|
(c)
|
Three and six month 2010 amounts include decreases of $0.1 million and $2.4 million, respectively, in net income attributable to our noncontrolling interests, and the six month 2009 amount includes a decrease of $0.2 million in net income attributable to our noncontrolling interests, all related to the combined effect of the three and six month 2010 and 2009 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, 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 $190.8 million decrease in cash attributable to higher payments made in 2010 for transportation rate settlements, refunds and reparations made pursuant to certain legal settlements reached with various shippers on our Pacific operations’ refined products pipelines. In May 2010, we paid $206.3 million to eleven of twelve shippers regarding the settlement of various transportation rate challenges filed with the Federal Energy Regulatory Commission (FERC) dating back as early as 1992. In May 2009, we made refund and settlement payments totaling $15.5 million to various shippers in connection with certain East Line rate settlement agreements;
|
|
▪
|
a $144.4 million decrease in cash from an interest rate swap termination payment we received in January 2009, when we terminated a fixed-to-variable interest rate swap agreement having a notional principal amount of $300 million and a maturity date of March 15, 2031;
|
|
▪
|
a $187.2 million increase in cash from overall higher partnership income—after adjusting for the following five non-cash items: (i) depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments); (ii) undistributed earnings from equity investees; (iii) income from the allowance for equity funds used during construction; (iv) income from the sale or casualty of property, plant and equipment and other net assets; and (v) a $158.0 million expense related to rate case liability adjustments recorded in the first quarter of 2010. The period-to-period increase in partnership income from our five reportable business segments in the first six months of 2010 versus the first six months of 2009 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes); and
|
|
▪
|
a $137.8 million increase in cash inflows relative to net changes in working capital items, primarily driven by (i) a $101.6 million increase in net cash inflows 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); and (ii) a $42.8 million increase in cash from higher payments in the first half of 2009 for natural gas storage on our Kinder Morgan Texas Pipeline system.
|
|
▪
|
a combined $1,129.3 million decrease in cash due to higher acquisitions of assets and investments. In the first six months of 2010, our cash outlays for strategic business acquisitions totaled $1,147.8 million, primarily consisting of the following (i) $921.4 million for a 50% equity ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business; (ii) $115.7 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. Each of these 2010 acquisitions is discussed further in Note 2 “Acquisitions, Joint Ventures, and Divestitures” to our consolidated financial statements included elsewhere in this report. In the first half of 2009, our cash payments for acquired assets totaled $18.5 million, including $18.0 million for the acquisition of certain marine vessels from Megafleet Towing Co., Inc.;
|
|
▪
|
a $109.6 million decrease in cash due to the full repayment received in the first half of 2009 of a loan we made in December 2008 to a single customer of our Texas intrastate natural gas pipeline group;
|
|
▪
|
a $621.9 million increase in cash due to lower contributions to equity investees in the first half of 2010. The increase in cash was driven by a $628.2 million decrease in combined contributions made to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Express Pipeline LLC in the first half of 2010, largely due to incremental contributions made in the first half of 2009 to partially fund our respective share of Rockies Express, Midcontinent Express, and Fayetteville Express pipeline system construction and/or pre-construction costs;
|
|
▪
|
a $345.5 million increase in cash due to lower capital expenditures in the first six months of 2010—largely due to the higher investment undertaken in the first half of 2009 to construct our Kinder Morgan Louisiana Pipeline and to expand and improve our Terminals business segment;
|
|
▪
|
a $93.3 million increase in cash due to higher capital distributions (distributions in excess of cumulative earnings) received in the first half of 2010, primarily related to distributions received from our equity investments in Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Express Pipeline LLC. Current accounting practice requires us to classify and report cumulative cash distributions in excess of cumulative equity earnings as a return of capital; however, this change in classification does not impact our cash available for distribution; and
|
|
▪
|
a $27.2 million increase in cash due to higher net proceeds received in the first half of 2010 from property sales and casualty insurance settlements, mainly related to insurance indemnifications received for (i) assets damaged during the 2008 hurricane season; (ii) property damaged at our Pasadena, Texas liquids terminal facility from a fire in September 2008; and (iii) a marine vessel dock damaged at our International Marine Terminals facility in March 2008.
|
|
▪
|
a $404.3 million increase in cash from overall debt financing activities—which include our issuances and payments of debt and our debt issuance costs. The period-to-period increase in cash from overall financing activities in the first half of 2010 was primarily due to (i) a $501.4 million increase in cash due to net commercial paper borrowings in the first half of 2010 (we had no commercial paper borrowings during the first six months of 2009); (ii) a $250.0 million increase in cash due to the February 1, 2009 retirement of the principal amount of our 6.30% senior notes that matured on that date; and (iii) a $325.0 million decrease in cash from lower net borrowings under our bank credit facility in the first half of 2010.
|
|
▪
|
a $29.7 million increase in cash from net changes in cash book overdrafts—resulting from timing differences on checks issued but not yet presented for payment;
|
|
▪
|
a $236.3 million decrease in cash from lower partnership equity issuances. The decrease relates to the $433.2 million we received, after commissions and underwriting expenses, from the sales of additional common units in the first half of 2010 (discussed in Note 5 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report), versus the $669.5 million we received from the sales of additional common units in the first half of 2009.
|
|
▪
|
a $102.1 million decrease in cash due to higher partnership distributions in the first six months of 2010, when compared to the same period last year. Further information regarding our distributions is included below in “—Partnership Distributions.”
|
|
▪
|
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 or the California Public Utilities Commission;
|
|
▪
|
our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to 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 and the Alberta, Canada oil sands;
|
|
▪
|
changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;
|
|
▪
|
changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;
|
|
▪
|
our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;
|
|
▪
|
our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
|
|
▪
|
interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;
|
|
▪
|
our ability to obtain insurance coverage without significant levels of self-retention of risk;
|
|
▪
|
acts of nature, sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits;
|
|
▪
|
capital and credit markets conditions, 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;
|
|
▪
|
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 —
|
Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
|
|
4.2 —
|
Certificate of the 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 5.30% Senior Notes due September 15, 2020, and the 6.55% Senior Notes due September 15, 2040.
|
*10.1—
|
Credit Agreement dated as of June 23, 2010 among Kinder Morgan Energy Partners, L.P., Kinder Morgan Operating L.P. (“B”), the lenders party thereto, Wells Fargo Bank, National Association as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A., and DnB NOR Bank ASA (filed as exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Current Report on Form 8-K filed June 24, 2010).
|
|
|
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.
|
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: July 30, 2010
|
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.
|
|
/s/ Kimberly A. Dang
|
|||
|
Kimberly A. Dang | |||
|
Vice President and Chief Financial Officer
|
|
/s/ David D. Kinder
|
|||
|
David D. Kinder
|
|||
|
Vice President and Treasurer
|
NO. [___] | U.S.$[__________] |
|
KINDER MORGAN ENERGY PARTNERS, L.P.,
|
|
By:
|
Kinder Morgan G.P., Inc.,
|
|
its general partner
|
|
By:
|
Kinder Morgan Management, LLC,
|
|
its delegate
|
|
By:
|
_________________________________ |
|
David D. Kinder
|
|
Vice President and Treasurer
|
(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 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;
|
(2)
|
the principal amount of the Security, or portion of a Security, being redeemed.
|
Six Months Ended June 30,
|
||||||||
|
2010
|
2009
|
||||||
Weighted Average Number of Limited Partners’ Units on which Limited Partners’ Net Income per Unit is Based
|
301.7 | 273.5 | ||||||
Calculation of Limited Partners’ interest in Net Income
|
||||||||
Amounts Attributable to Kinder Morgan Energy Partners, L.P.:
|
||||||||
Net Income
|
$ | 586.5 | $ | 587.7 | ||||
Less: General Partner’s interest in Net Income
|
(341.7 | ) | (456.5 | ) | ||||
Limited Partners’ interest in Net Income
|
$ | 244.8 | $ | 131.2 | ||||
Limited Partners’ Net Income per Unit
|
$ | 0.81 | $ | 0.48 |
Six Months Ended
|
Six Months Ended
|
|||||||
|
June 30, 2010
|
June 30, 2009
|
||||||
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
|
$ | 507.5 | $ | 549.7 | ||||
Add:
|
||||||||
Fixed charges Services
|
258.7 | 236.4 | ||||||
Amortization of capitalized interest
|
2.0 | 1.8 | ||||||
Distributed income of equity investees
|
101.9 | 100.3 | ||||||
Less:
|
||||||||
Interest capitalized from continuing operations
|
(7.1 | ) | (21.3 | ) | ||||
Noncontrolling interests in pre-tax income of subsidiaries
with no fixed charges
|
(0.1 | ) | (0.1 | ) | ||||
Income as adjusted
|
$ | 862.9 | $ | 866.8 | ||||
Fixed charges:
Interest and debt expense, net per statements of income (includes amortization of debt discount, premium, and debt issuance costs; excludes capitalized interest)
|
$ | 248.0 | $ | 227.3 | ||||
Add:
|
||||||||
Portion of rents representative of the interest factor Services
|
10.7 | 9.1 | ||||||
Fixed charges
|
$ | 258.7 | $ | 236.4 | ||||
Ratio of earnings to fixed charges
|
3.34 | 3.67 | ||||||
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;
|
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;
|
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.
|
Dated: July 30, 2010
|
/s/ Richard D. Kinder
|