10-Q 1 kmp-2012930x10q.htm 10-Q KMP-2012.9.30-10Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
F O R M 10‑Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1‑11234

KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

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

500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713‑369‑9000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [   ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [   ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer [   ] Non-accelerated filer [   ] (Do not check if a smaller reporting company) Smaller reporting company [   ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [   ] No [X]
The Registrant had 246,381,091 common units outstanding as of October 29, 2012.

1


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
Page
Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2


PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions Except Per Unit Amounts)
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
Revenues
 
 
 
 
 
 
 
Natural gas sales
$
675

 
$
925

 
$
1,756

 
$
2,575

Services
989

 
737

 
2,585

 
2,190

Product sales and other
669

 
449

 
1,791

 
1,201

Total Revenues
2,333

 
2,111

 
6,132

 
5,966

 
 
 
 
 
 
 
 
Operating Costs, Expenses and Other
 
 
 
 
 
 
 
Gas purchases and other costs of sales
828

 
914

 
2,036

 
2,550

Operations and maintenance
429

 
399

 
1,094

 
1,163

Depreciation, depletion and amortization
292

 
247

 
796

 
685

General and administrative
131

 
100

 
379

 
387

Taxes, other than income taxes
63

 
37

 
169

 
133

Other expense (income)
(8
)
 
(1
)
 
(28
)
 
(15
)
Total Operating Costs, Expenses and Other
1,735

 
1,696

 
4,446

 
4,903

 
 
 
 
 
 
 
 
Operating Income
598

 
415

 
1,686

 
1,063

 
 
 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
 
 
Earnings from equity investments
100

 
52

 
225

 
155

Amortization of excess cost of equity investments
(1
)
 
(2
)
 
(5
)
 
(5
)
Interest expense
(184
)
 
(134
)
 
(480
)
 
(396
)
Interest income
8

 
6

 
19

 
16

Loss on remeasurement of previously held equity interest in KinderHawk to fair value (Note 2)

 
(167
)
 

 
(167
)
Other, net
4

 
3

 
14

 
11

Total Other Income (Expense)
(73
)
 
(242
)
 
(227
)
 
(386
)
 
 
 
 
 
 
 
 
Income from Continuing Operations Before Income Taxes
525

 
173

 
1,459

 
677

 
 
 
 
 
 
 
 
Income Tax (Expense) Benefit
(11
)
 
(12
)
 
(40
)
 
(33
)
 
 
 
 
 
 
 
 
Income from Continuing Operations
514

 
161

 
1,419

 
644

 
 
 
 
 
 
 
 
Discontinued Operations (Note 2)
 
 
 
 
 
 
 
Income from operations of FTC Natural Gas Pipelines disposal group
47

 
55

 
145

 
145

Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value
(178
)
 

 
(827
)
 

Income (Loss) from Discontinued Operations
(131
)
 
55

 
(682
)
 
145

 
 
 
 
 
 
 
 
Net Income
383

 
216

 
737

 
789

 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
(4
)
 
(1
)
 
(12
)
 
(6
)
 
 
 
 
 
 
 
 
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
$
379

 
$
215

 
$
725

 
$
783

 
 
 
 
 
 
 
 
Calculation of Limited Partners’ Interest in Net Loss
 
 
 
 
 
 
 
Attributable to Kinder Morgan Energy Partners, L.P.:
 
 
 
 
 
 
 
Income from Continuing Operations
$
509

 
$
161

 
$
1,400

 
$
640

Less: Pre-acquisition income from operations of drop-down asset group allocated to General Partner (Note 2)
(36
)
 

 
(23
)
 

Less: General Partner’s remaining Interest
(367
)
 
(298
)
 
(1,024
)
 
(870
)
Limited Partners’ Interest
106

 
(137
)
 
353

 
(230
)
Add: Limited Partners’ Interest in Discontinued Operations
(128
)
 
54

 
(668
)
 
142

Limited Partners’ Interest in Net Loss
$
(22
)
 
$
(83
)
 
$
(315
)
 
$
(88
)
 
 
 
 
 
 
 
 
Limited Partners’ Net Income (Loss) per Unit:
 
 
 
 
 
 
 
Income (Loss) from Continuing Operations
$
0.30

 
$
(0.41
)
 
$
1.02

 
$
(0.71
)
Income (Loss) from Discontinued Operations
(0.36
)
 
0.16

 
(1.93
)
 
0.44

Net Loss
$
(0.06
)
 
$
(0.25
)
 
$
(0.91
)
 
$
(0.27
)
 
 
 
 
 
 
 
 
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit
356

 
331

 
345

 
323

 
 
 
 
 
 
 
 
Per Unit Cash Distribution Declared
$
1.26

 
$
1.16

 
$
3.69

 
$
3.45

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

3



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
Net Income
$
383

 
$
216

 
$
737

 
$
789

 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss):
 
 
 
 
 
 
 
Change in fair value of derivatives utilized for hedging purposes
(90
)
 
387

 
99

 
289

Reclassification of change in fair value of derivatives to net income
(10
)
 
49

 
10

 
189

Foreign currency translation adjustments
70

 
(163
)
 
68

 
(102
)
Adjustments to pension and other postretirement benefit plan liabilities, net of tax

 

 

 
(13
)
Total Other Comprehensive Income (Loss)
(30
)
 
273

 
177

 
363

 
 
 
 
 
 
 
 
Comprehensive Income
353

 
489

 
914

 
1,152

Comprehensive Income Attributable to Noncontrolling Interests
(4
)
 
(5
)
 
(14
)
 
(10
)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.
$
349

 
$
484

 
$
900

 
$
1,142

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

4


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions)
 
September 30,
2012
 
December 31,
2011
ASSETS
(Unaudited)
 
 
Current assets
 
 
 
Cash and cash equivalents
$
532

 
$
409

Restricted deposits
6

 

Accounts, notes and interest receivable, net
956

 
884

Inventories
241

 
110

Gas in underground storage
56

 
62

Fair value of derivative contracts
59

 
72

Assets held for sale
1,859

 

Other current assets
59

 
39

Total Current assets
3,768

 
1,576

 
 
 
 
Property, plant and equipment, net
19,326

 
15,596

Investments
3,070

 
3,346

Notes receivable
168

 
165

Goodwill
4,605

 
1,436

Other intangibles, net
1,115

 
1,152

Fair value of derivative contracts
705

 
632

Deferred charges and other assets
836

 
200

Total Assets
$
33,593

 
$
24,103

LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities
 
 
 
Current portion of debt
$
2,697

 
$
1,638

Cash book overdrafts
63

 
21

Accounts payable
849

 
706

Accrued interest
149

 
259

Accrued taxes
140

 
38

Deferred revenues
97

 
100

Fair value of derivative contracts
41

 
121

Accrued other current liabilities
526

 
236

Total Current liabilities
4,562

 
3,119

 
 
 
 
Long-term liabilities and deferred credits
 
 
 
Long-term debt
 
 
 
Outstanding
15,217

 
11,183

Debt fair value adjustments
1,530

 
1,055

Total Long-term debt
16,747

 
12,238

Deferred income taxes
262

 
250

Fair value of derivative contracts
15

 
39

Other long-term liabilities and deferred credits
950

 
853

Total Long-term liabilities and deferred credits
17,974

 
13,380

 
 
 
 
Total Liabilities
22,536

 
16,499

Commitments and contingencies (Notes 4 and 10)


 
 
Partners’ Capital
 
 
 
Common units
4,360

 
4,347

Class B units
18

 
42

i-units
3,492

 
2,857

General partner
2,856

 
259

Accumulated other comprehensive income
178

 
3

Total Kinder Morgan Energy Partners, L.P. Partners’ Capital
10,904

 
7,508

Noncontrolling interests
153

 
96

Total Partners’ Capital
11,057

 
7,604

Total Liabilities and Partners’ Capital
$
33,593

 
$
24,103

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

5


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
(Unaudited)
 
Nine Months Ended
September 30,
 
2012
 
2011
Cash Flows From Operating Activities
 
 
 
Net Income
$
737

 
$
789

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
803

 
705

Amortization of excess cost of equity investments
5

 
5

Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value (Note 2)
827

 

Loss on remeasurement of previously held interest in Kinderhawk to fair value (Note 2)

 
167

Noncash compensation expense allocated from parent (Note 9)

 
90

Earnings from equity investments
(289
)
 
(214
)
Distributions from equity investments
277

 
201

Proceeds from termination of interest rate swap agreements
53

 
73

Changes in components of working capital:
 
 
 
Accounts receivable
(40
)
 
28

Inventories
(98
)
 
9

Other current assets
13

 
(2
)
Accounts payable
41

 
(9
)
Cash book overdrafts
42

 
9

Accrued interest
(138
)
 
(143
)
Accrued taxes
74

 
47

Accrued liabilities
49

 
(2
)
Rate reparations, refunds and other litigation reserve adjustments
(42
)
 
161

Other, net

 
70

Net Cash Provided by Operating Activities
2,314

 
1,984

 
 
 
 
Cash Flows From Investing Activities
 
 
 
Payment to KMI for drop-down asset group, net of cash acquired (Note 2)
(3,482
)
 

Acquisitions of assets and investments
(72
)
 
(945
)
Repayments from related party
42

 
29

Capital expenditures
(1,273
)
 
(838
)
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
36

 
29

(Investments in) Net proceeds from margin and restricted deposits
(16
)
 
56

Contributions to equity investments
(155
)
 
(297
)
Distributions from equity investments in excess of cumulative earnings
120

 
165

Refined products, natural gas liquids and transmix line-fill
14

 
3

Other, net

 
1

Net Cash Used in Investing Activities
(4,786
)
 
(1,797
)
 
 
 
 
Cash Flows From Financing Activities
 
 
 
Issuance of debt
8,378

 
6,356

Payment of debt
(5,074
)
 
(5,538
)
Debt issue costs
(16
)
 
(17
)
Proceeds from issuance of i-units
727

 

Proceeds from issuance of common units
387

 
813

Contributions from noncontrolling interests
40

 
15

Distributions to partners and noncontrolling interests:
 
 
 
Common units
(847
)
 
(762
)
Class B units
(19
)
 
(18
)
General Partner
(970
)
 
(859
)
Noncontrolling interests
(23
)
 
(20
)
Other, net
(1
)
 

Net Cash Provided by (Used in) Financing Activities
2,582

 
(30
)
 
 
 
 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
13

 
(15
)
 
 
 
 
Net increase in Cash and Cash Equivalents
123

 
142

Cash and Cash Equivalents, beginning of period
409

 
129

Cash and Cash Equivalents, end of period
$
532

 
$
271

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

6


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
(Unaudited)
 
Nine Months Ended
September 30,
 
2012
 
2011
Noncash Investing and Financing Activities
 
 
 
Net assets acquired by the transfer of the drop-down asset group
$
6,371

 
$

Assets acquired or liabilities settled by the issuance of common units
$
686

 
$
24

Assets acquired by the assumption or incurrence of liabilities
$

 
$
180

Contribution of net assets to investments
$

 
$
8

Sale of investment ownership interest in exchange for note
$

 
$
4

 
 
 
 
Supplemental Disclosures of Cash Flow Information
 
 
 
Cash paid during the period for interest (net of capitalized interest)
$
586

 
$
510

Cash paid during the period for income taxes
$
16

 
$
9

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


7


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries. We own an interest in or operate approximately 53,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described further in Note 8). Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals, and handle such products as ethanol, coal, petroleum coke and steel. We are also the leading producer and transporter of carbon dioxide, commonly called CO2, for enhanced oil recovery projects in North America. Our general partner is owned by Kinder Morgan, Inc., as discussed below.
Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.
Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold to a third party 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.
On February 29, 2012, Kinder Morgan Kansas, Inc., a Kansas corporation, merged with and into its parent, Kinder Morgan Holdco DE Inc., a Delaware corporation and a wholly-owned subsidiary of KMI. Immediately following this merger, Kinder Morgan Holdco DE Inc. (the surviving legal entity from the merger) then merged with and into its parent KMI. KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.” As of September 30, 2012, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate 13% interest in us.
On May 25, 2012, KMI acquired all of the outstanding shares of El Paso Corporation (referred to as EP in this report) in a transaction that created one of the largest energy companies in the United States.
On March 15, 2012, KMI announced that it had reached an agreement with the U.S. Federal Trade Commission (FTC) to divest certain of our assets in order to receive regulatory approval for its proposed EP acquisition. Subject to final FTC approval, KMI agreed to sell our (i) Kinder Morgan Interstate Gas Transmission natural gas pipeline system; (ii) Trailblazer natural gas pipeline system; (iii) Casper and Douglas natural gas processing operations; and (iv) 50% equity investment in the Rockies Express natural gas pipeline system. In this report, we refer to this combined group of assets as our FTC Natural Gas Pipelines disposal group.
Prior to KMI’s announcement, we included the assets we are required to sell pursuant to the FTC's order in our Natural Gas Pipelines business segment. Because this combined group of assets, including our equity investment in Rockies Express, has its own operations and cash flows, we now report this FTC Natural Gas Pipelines disposal group as a business held for sale. We expect to complete the sale of our FTC Natural Gas Pipelines disposal group in November 2012. For more information about this planned divestiture, see both “—Basis of Presentation” below and Note 2 "Acquisitions and Discontinued Operations—FTC Natural Gas Pipelines Disposal Group - Discontinued Operations."
Kinder Morgan Management, LLC
Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to

8


manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. KMR’s shares representing limited liability company interests trade on the New York Stock Exchange under the symbol “KMR.”
More information about the entities referred to above and the delegation of control agreement is contained in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed May 1, 2012. In this report, we refer to our Annual Report on Form 10-K for the year ended December 31, 2011 as our 2011 Form 10-K.
Basis of Presentation
We have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission. These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America and referred to in this report as the Codification. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with the Codification. We believe, however, that our disclosures are adequate to make the information presented not misleading.
Our accompanying consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair statement of our financial results for the interim periods, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.
Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise. Canadian dollars are designated as C$. Our consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.
Our financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 9 “Related Party Transactions—Asset Acquisitions,” KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa.  Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
Following KMI’s March 15, 2012 announcement of its intention to sell the assets that comprise our FTC Natural Gas Pipelines disposal group (described above in “—Kinder Morgan, Inc. and Kinder Morgan G.P., Inc.”), we accounted for the disposal group as discontinued operations in accordance with the provisions of the “Presentation of Financial Statements—Discontinued Operations” Topic of the Codification. Accordingly, we (i) reclassified and excluded the FTC Natural Gas Pipelines disposal group’s results of operations from our results of continuing operations and reported the disposal group’s results of operations separately as “Income from operations of FTC Natural Gas Pipelines disposal group” within the discontinued operations section of our accompanying consolidated statements of income for all periods presented; (ii) separately reported a “Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statements of income for the three and nine months ended September 30, 2012; and (iii) reclassified and reported the disposal group’s combined assets within “Assets held for sale” in our accompanying consolidated balance sheet as of September 30, 2012.
Because the disposal group’s combined liabilities were not material to our consolidated balance sheet, we included the disposal group’s liabilities within “Accrued other current liabilities” in our accompanying consolidated balance sheet as of September 30, 2012. In addition, we did not elect to present separately the operating, investing and financing cash flows related to the disposal group in our accompanying consolidated statements of cash flows. For more information about the discontinued operations of our FTC Natural Gas Pipelines disposal group, see Note 2 "Acquisitions and Discontinued

9


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

2. Acquisitions and Discontinued Operations
El Paso Midstream Investment Company, LLC
Effective June 1, 2012, we acquired from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates, referred to as KKR) a 50% ownership interest in El Paso Midstream Investment Company, LLC, a joint venture that owns (i) the Altamont natural gas gathering, processing and treating assets located in the Uinta Basin in Utah; and (ii) the Camino Real natural gas and oil gathering system located in the Eagle Ford shale formation in South Texas. We acquired our equity interest for an aggregate consideration of $289 million in common units (we issued 3,792,461 common units and determined each unit's value based on the $76.23 closing market price of the common units on the New York Stock Exchange on the June 4, 2012 issuance date). A subsidiary of KMI owns the remaining 50% interest in the joint venture.
We account for our investment under the equity method of accounting, and our investment and our pro rata share of the joint venture’s operating results are included as part of our Natural Gas Pipelines business segment. As of September 30, 2012, our net equity investment in the joint venture totaled $301 million and is included within “Investments” on our accompanying consolidated balance sheet.
August 2012 KMI Asset Drop-Down    
Effective August 1, 2012, we acquired the full ownership interest in the Tennessee Gas natural gas pipeline system and a 50% ownership interest in the El Paso Natural Gas pipeline system from KMI for an aggregate consideration of approximately $6.2 billion. In this report, we refer to this acquisition of assets from KMI as the drop-down transaction; the combined group of assets acquired from KMI as the drop-down asset group; the Tennessee Gas natural gas pipeline system or Tennessee Gas Pipeline L.L.C. as TGP, and the El Paso Natural Gas pipeline system or El Paso Natural Gas Pipeline LLC as EPNG.
We purchased the drop-down asset group from KMI in order to replace the cash flows associated with the FTC Natural Gas Pipelines disposal group that we will divest. Our consideration to KMI consisted of (i) $3.5 billion in cash; (ii) 4,667,575 common units (valued at $0.4 billion based on the $81.52 closing market price of the common units on the New York Stock Exchange on the August 13, 2012 issuance date); and (iii) $2.3 billion in assumed debt (consisting of the combined carrying value of 100% of TGP's debt borrowings and 50% of EPNG's debt borrowings as of August 1, 2012, excluding any debt fair value adjustments). The terms of the drop-down transaction were approved on behalf of KMI by the independent members of its board of directors and on our behalf by the audit committees and the boards of directors of both our general partner and KMR, in its capacity as the delegate of our general partner, following the receipt by the independent directors of KMI and the audit committees of our general partner and KMR of separate fairness opinions from different independent financial advisors.
KMI acquired the drop-down asset group as part of its acquisition of EP on May 25, 2012 (discussed above in Note 1). Pursuant to current accounting principles in conformity with the Codification, KMI accounted for its acquisition of the drop-down asset group under the purchase accounting method, and we accounted for the drop-down transaction as a transfer of net assets between entities under common control. Accordingly, we prepared our consolidated financial statements and the related financial information contained in this report to reflect the transfer of net assets from KMI to us as if such transfer had taken place on May 25, 2012. Specifically, we (i) recognized the acquired assets and assumed liabilities at KMI's carrying value as of its acquisition date, May 25, 2012 (including all of KMI's purchase accounting adjustments); (ii) recognized any difference between our purchase price and the carrying value of the net assets we

10


acquired as an adjustment to our Partners' Capital (specifically, as an adjustment to our general partner's capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after KMI's May 25, 2012 acquisition of EP, to reflect our results on a consolidated combined basis including the results of the drop-down asset group as of or at the beginning of the respective period.
Additionally, because KMI both controls us and consolidates our financial statements into its consolidated financial statements as a result of its ownership of our general partner, we fully allocated the earnings of the drop-down asset group for the period beginning May 25, 2012 and ending August 1, 2012 to our general partner and we reported this amount separately as “Pre-acquisition income from operations of drop-down asset group allocated to General Partner" within the Calculation of Limited Partners' Interest in Net Loss section of our accompanying consolidated statements of income for the three and nine months ended September 30, 2012. For all periods beginning after our acquisition date of August 1, 2012, we allocated our earnings (including the earnings from the drop-down asset group) to all of our partners according to our partnership agreements. For more information on the changes to our Partners' Capital related to the drop-down transaction, see Note 5 "Partners' Capital—Changes in Partners' Capital."
TGP is a 13,900 mile pipeline system with a transport design capacity of approximately 7.5 billion cubic feet per day of natural gas. It transports natural gas from Louisiana, the Gulf of Mexico and south Texas to the northeastern United States, including the metropolitan areas of New York City and Boston. EPNG is a 10,200 mile pipeline system with a design capacity of approximately 5.6 billion cubic feet per day of natural gas. It transports natural gas from the San Juan, Permian and Anadarko basins to California, other western states, Texas and northern Mexico. Combined, the two pipeline systems have more than 200 billion cubic feet of working natural gas storage capacity.
The drop-down asset group is included in our Natural Gas Pipelines reportable business segment. We account for our 100% ownership interest in TGP under the consolidation method and we account for our 50% investment in EPNG under the equity method of accounting. As of September 30, 2012, our net equity investment in EPNG totaled $870 million and is included within “Investments” on our accompanying consolidated balance sheet.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement information for the nine months ended September 30, 2012 and 2011, assumes that the drop-down transaction had occurred as of January 1, 2011. We have prepared these unaudited pro forma financial results for comparative purposes only. These unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the drop-down transaction as of January 1, 2011 or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:
 
Pro Forma
Nine Months Ended
September 30,
 
2012
 
2011
 
(Unaudited)
Revenues
$
6,549

 
$
6,640

Income from Continuing Operations
$
1,396

 
$
844

Income (Loss) from Discontinued Operations
$
(682
)
 
$
145

Net Income
$
714

 
$
989

Net Income Attributable to Noncontrolling Interests
$
(12
)
 
$
(8
)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
$
702

 
$
981

 
 
 
 
Limited Partners’ Net Income (Loss) per Unit:
 
 
 
Income (Loss) from Continuing Operations
$
0.82

 
$
(0.19
)
Income (Loss) from Discontinued Operations
(1.89
)
 
0.43

Net Income (Loss)
$
(1.07
)
 
$
0.24


FTC Natural Gas Pipelines Disposal Group – Discontinued Operations

11


As described above in Note 1 “General—Basis of Presentation,” in March 2012, we began accounting for our FTC Natural Gas Pipelines disposal group as discontinued operations. We had previously remeasured the disposal group in the first half of 2012 to reflect our initial assessment of its fair value as a result of the FTC mandated sale requirement, and based on additional information gained in the sale process during the current quarter, we recognized additional loss amounts from fair value remeasurement and sales liability adjustments. For the nine months ended September 30, 2012, we recognized a combined $827 million non-cash loss from both remeasurement and estimated costs to sell, and we reported this loss amount separately as “Loss from costs to sell and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value” within the discontinued operations section of our accompanying consolidated statement of income for the nine months ended September 30, 2012.
We also reclassified the fair value of the disposal group’s assets and included this fair value amount within “Assets held for sale” in our accompanying consolidated balance sheet as of September 30, 2012 (because the disposal group's combined liabilities were not material to our consolidated balance sheet as of this date, we included the disposal group’s liabilities within “Accrued other current liabilities.”) Our “Assets held for sale” are primarily comprised of property, plant and equipment, and our investment in the Rockies Express natural gas pipeline system.
Summarized financial information for the disposal group is as follows (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
Operating revenues
$
71

 
$
83

 
$
204

 
$
241

Operating expenses
(45
)
 
(42
)
 
(116
)
 
(136
)
Depreciation and amortization

 
(7
)
 
(7
)
 
(20
)
Other expense
(1
)
 

 
(1
)
 

Earnings from equity investments
22

 
21

 
64

 
59

Interest income and Other, net

 
1

 
1

 
2

Income tax (expense) benefit

 
(1
)
 

 
(1
)
Earnings from discontinued operations
$
47

 
$
55

 
$
145

 
$
145


KinderHawk Field Services LLC
Effective July 1, 2011, we acquired from Petrohawk Energy Corporation the remaining 50% equity ownership interest in KinderHawk Field Services LLC (KinderHawk) that we did not already own. Following our acquisition of the remaining ownership interest, we changed our method of accounting from the equity method to full consolidation, and due to us acquiring a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value. We recognized a $167 million non-cash loss as a result of this remeasurement, and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011. For additional information regarding our July 2011 KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

3. Goodwill
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes, but combined with Products Pipelines for presentation in the table below); (iii) Natural Gas Pipelines; (iv) CO2; (v) Terminals; and (vi) Kinder Morgan Canada. There were no impairment charges resulting from our May 31, 2012 impairment test, and no event indicating an impairment has occurred subsequent to that date.
Changes in the gross amounts of our goodwill and accumulated impairment losses for the nine months ended

12


September 30, 2012 are summarized as follows (in millions):
 
Products
Pipelines
 
Natural Gas
Pipelines
 
CO2
 
Terminals
 
Kinder Morgan
Canada
 
Total
Historical Goodwill
$
263

 
$
557

 
$
46

 
$
326

 
$
621

 
$
1,813

Accumulated impairment losses(a)

 

 

 

 
(377
)
 
(377
)
Balance as of December 31, 2011
263

 
557

 
46

 
326

 
244

 
1,436

Acquisitions(b)

 
3,246

 

 

 

 
3,246

Disposals(c)

 
(85
)
 

 

 

 
(85
)
Currency translation adjustments

 

 

 

 
8

 
8

Balance as of September 30, 2012
$
263

 
$
3,718

 
$
46

 
$
326

 
$
252

 
$
4,605

__________
(a)
On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007. Following the provisions of U.S. generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired. Based on this determination, KMI recorded a goodwill impairment charge of $377 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.
(b)
Acquisition amount relates to our August 1, 2012 acquisition of the drop-down asset group from KMI as discussed in Note 2.
(c)
Amount represents reclassification of FTC Natural Gas Pipelines disposal group’s goodwill to “Assets held for sale.” Since our FTC Natural Gas Pipelines disposal group represents a significant portion of our Natural Gas Pipelines business segment, we allocated the goodwill of the segment based on the relative fair value of the portion being disposed of and the portion of the segment remaining.

4. Debt
The following table summarizes the net carrying value of our outstanding debt, excluding our debt fair value adjustments, as of September 30, 2012 and December 31, 2011 (in millions):
 
September 30,
2012
 
December 31,
2011
Current portion of debt(a)
$
2,697

 
$
1,638

Long-term portion of debt
15,217

 
11,183

Net carrying value of debt(b)
$
17,914

 
$
12,821

__________
(a)
As of September 30, 2012 and December 31, 2011, includes commercial paper borrowings of $2,664 million and $645 million, respectively.
(b)
Excludes debt fair value adjustments. As of September 30, 2012 and December 31, 2011, our "Debt fair value adjustments" increased our debt balances by $1,530 million and $1,055 million, respectively. In addition to normal adjustments associated with valuing our debt obligations equal to the present value of amounts to be paid determined at appropriate current interest rates, our debt fair value adjustments also include (i) the value of our interest rate swap agreements; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements.

Changes in our outstanding debt, excluding debt fair value adjustments, during the nine months ended September 30, 2012 are summarized as follows (in millions):

13


Debt borrowings
 
Interest rate
 
Increase / (decrease)
 
Cash received / (paid)
Issuances and Assumptions
 
 
 
 
 
 
Senior notes due September 1, 2022(a)
 
3.95
%
 
$
1,000

 
$
998

Senior notes due February 15, 2023(b)
 
3.45
%
 
625

 
622

Senior notes due August 15, 2042(b)
 
5.00
%
 
625

 
621

Commercial paper
 
variable

 
5,561

 
5,561

Bridge loan credit facility due February 6, 2013(c)
 
variable

 
576

 
576

Tennessee Gas Pipeline L.L.C. - senior notes due February 1, 2016(d)
 
8.00
%
 
250

 

Tennessee Gas Pipeline L.L.C. - senior notes due April 4, 2017(d)
 
7.50
%
 
300

 

Tennessee Gas Pipeline L.L.C. - senior notes due March 15, 2027(d)
 
7.00
%
 
300

 

Tennessee Gas Pipeline L.L.C. - senior notes due October 15, 2028(d)
 
7.00
%
 
400

 

Tennessee Gas Pipeline L.L.C. - senior notes due June 15, 2032(d)
 
8.375
%
 
240

 

Tennessee Gas Pipeline L.L.C. - senior notes due April 1, 2037(d)
 
7.625
%
 
300

 

Total increases in debt
 
 
 
$
10,177

 
$
8,378

 
 
 
 
 
 
 
Repayments and other
 
 
 
 
 
 
Senior notes due March 15, 2012(a)
 
7.125
%
 
$
(450
)
 
$
(450
)
Senior notes due September 15, 2012(e)
 
5.85
%
 
(500
)
 
(500
)
Commercial paper
 
variable

 
(3,542
)
 
(3,542
)
Bridge loan credit facility due February 6, 2013(c)
 
variable

 
(576
)
 
(576
)
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014
 
5.23
%
 
(5
)
 
(5
)
Kinder Morgan Arrow Terminals L.P. - note due April 4, 2014
 
6.0
%
 
(1
)
 
(1
)
Kinder Morgan Operating L.P. "A" - BP note due March 31, 2012
 
5.40
%
 
(5
)
 

Kinder Morgan Canada Company - BP note due March 31, 2012
 
5.40
%
 
(5
)
 

Total decreases in debt
 
 
 
$
(5,084
)
 
$
(5,074
)
__________
(a)
On March 14, 2012, we completed a public offering of $1.0 billion in principal amount of 3.95% senior notes due September 1, 2022. We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $994 million, and we used the proceeds both to repay our $450 million 7.125% senior notes that matured on March 15, 2012 and to reduce the borrowings under our commercial paper program.
(b)
On August 13, 2012, we completed a public offering of $1,250 million in principal amount of senior notes in two separate series, consisting of $625 million of 3.45% notes due February 15, 2023 and $625 million of 5.00% notes due August 15, 2042. We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $1,236 million, and we used the proceeds to pay a portion of the purchase price for the drop-down transaction.
(c)
On August 6, 2012, we entered into a second credit agreement with us as borrower; Wells Fargo Bank, National Association, as administrative agent; Barclays Bank PLC, as syndication agent; and a syndicate of other lenders. This credit agreement provided for borrowings up to $2.0 billion pursuant to a short-term bridge loan credit facility with a term of six months. The covenants of this facility are substantially similar to the covenants of our existing senior unsecured revolving credit facility that is due July 1, 2016, and similar to our existing credit facility, borrowings under this bridge loan credit facility may be used to back our commercial paper issuances and for other general partnership purposes (including to pay a portion of the purchase price for the drop-down transaction). In August 2012, we made borrowings of $576 million under our short-term bridge loan credit facility to pay a portion of the purchase price for the drop-down transaction. We then repaid these credit facility borrowings in August 2012 with incremental borrowings under our commercial paper program, and as of September 30, 2012, our bridge loan credit facility was not drawn on.
The size of our bridge loan credit facility will be reduced by an amount equal to the net cash proceeds of certain debt and equity issuances in excess of $1.65 billion, and as of September 30, 2012, our bridge loan credit facility was reduced to allow for maximum borrowings of $1.685 billion. We are also required to prepay borrowings under this credit facility with net proceeds received from certain debt and equity issuances and from the expected divestiture of our FTC Natural Gas Pipelines disposal group. All such prepayments will automatically reduce the borrowing capacity of the credit facility. In addition, in conjunction with the establishment of this short-term bridge loan credit facility, we increased our commercial paper program to provide for the

14


issuance of up to $3.885 billion of commercial paper (up from $2.2 billion).
(d)
Our subsidiary, Tennessee Gas Pipeline L.L.C. is the obligor of six separate series of fixed-rate unsecured senior notes having a combined principal amount of $1,790 million. We assumed these debt borrowings as part of the drop-down transaction.
(e)
On September 15, 2012, we paid $500 million to retire the principal amount of our 5.85% senior notes that matured on that date.
We had, as of September 30, 2012, approximately $1.0 billion of combined borrowing capacity available under our two separate unsecured credit facilities. As of this date, the combined $3,885 million amount available for borrowing under our two credit facilities was reduced by a combined amount of $2,886 million, consisting of $2,664 million of commercial paper borrowings and $222 million of letters of credit, consisting of (i) a $100 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $86 million in three letters of credit that support tax-exempt bonds; (iii) a $12 million letter of credit that supports debt securities issued by the Express pipeline system; and (iv) a combined $24 million in other letters of credit supporting other obligations of us and our subsidiaries.
For additional information regarding our debt facilities and for information on our contingent debt agreements, see Note 8 “Debt” and Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.

5. Partners’ Capital
Limited Partner Units
As of September 30, 2012 and December 31, 2011, our Partners’ Capital included the following limited partner units:
 
September 30,
2012
 
December 31,
2011
Common units
246,111,590

 
232,677,222

Class B units
5,313,400

 
5,313,400

i-units
113,276,125

 
98,509,389

Total limited partner units
364,701,115

 
336,500,011


The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s incentive distribution rights. Our general partner has an effective 2% interest in us, excluding its right to receive incentive distributions.
As of September 30, 2012, (i) KMI and its consolidated affiliates (excluding our general partner) held 19,314,003 common units; (ii) our general partner held 1,724,000 common units; (iii) a wholly-owned subsidiary of KMI held all of our Class B units; and (iv) KMR held all of our i-units. As of December 31, 2011, (i) KMI and its consolidated affiliates (excluding our general partner) held 14,464,428 common units; (ii) our general partner held 1,724,000 common units; (iii) a wholly-owned subsidiary of KMI held all of our Class B units; and (iv) KMR held all of our i-units. Our Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. Our i-units are a separate class of limited partner interests in us and are not publicly traded. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.
Changes in Partners’ Capital
For each of the nine month periods ended September 30, 2012 and 2011, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income are summarized as follows (in millions):

15


 
Nine Months Ended September 30,
 
2012
 
2011
 
KMP
 
Noncontrolling
Interests
 
Total
 
KMP
 
Noncontrolling interests
 
Total
Beginning Balance
$
7,508

 
$
96

 
$
7,604

 
$
7,211

 
$
82

 
$
7,293

Units issued for cash
1,114

 

 
1,114

 
813

 

 
813

Units issued as consideration in the acquisition of assets
686

 

 
686

 
24

 

 
24

Distributions paid in cash
(1,836
)
 
(23
)
 
(1,859
)
 
(1,639
)
 
(20
)
 
(1,659
)
Adjustments to capital due to acquisitions from KMI(a)
2,483

 
25

 
2,508

 

 

 

Contribution from KMI for FTC Natural Gas Pipelines disposal group selling expenses(b)
45

 

 
45

 

 

 

Noncash compensation expense allocated from KMI(c)

 

 

 
89

 
1

 
90

Cash contributions

 
40

 
40

 

 
15

 
15

Other adjustments
4

 
1

 
5

 
(3
)
 

 
(3
)
Comprehensive income
900

 
14

 
914

 
1,142

 
10

 
1,152

Ending Balance
$
10,904

 
$
153

 
$
11,057

 
$
7,637

 
$
88

 
$
7,725

__________
(a)
Amounts relate to the drop-down transaction, described in Note 2. We determined that the drop-down transaction constituted a transfer of net assets between entities under common control, and accordingly, we recognized the assets we acquired and the liabilities we assumed at KMI's carrying value (including all purchase accounting adjustments from KMI's acquisition of the drop-down asset group from EP effective May 25, 2012). We then recognized the difference between our purchase price and the carrying value of the assets acquired and liabilities assumed as an adjustment to our Partners' Capital. As of September 30, 2012, the carrying value of the assets we acquired and the liabilities we assumed totaled $6,371 million. We paid to KMI $3,482 million in cash, issued to KMI 4,667,575 common units valued at $381 million, and recognized a non-cash increase of $2,508 million in our Partners' Capital. The increase to Partners' Capital consisted of a $2,483 million increase in our general partner's 1% general partner capital interest in us, and a $25 million increase in our general partner's 1.0101% general partner capital interest in our subsidiary Kinder Morgan Operating L.P. "A" (a noncontrolling interest to us).
(b)
For further information about this contribution, see Note 9.
(c)
For further information about this expense, see Note 9. We do not have any obligation, nor do we expect to pay any amounts related to this expense.

During each of the nine month periods ended September 30, 2012 and 2011, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.
Equity Issuances
On February 27, 2012, we entered into a third amended and restated equity distribution agreement with UBS Securities LLC (UBS) which increased the aggregate offering price of our common units to up to $1.9 billion (up from $1.2 billion). During the three and nine months ended September 30, 2012, we issued 1,357,946 and 4,772,741, respectively, of our common units pursuant to our equity distribution agreement with UBS. We received net proceeds of $110 million and $387 million, respectively, from the issuance of these common units and we used the proceeds to reduce the borrowings under our commercial paper program. For additional information regarding our equity distribution agreement, see Note 10 to our consolidated financial statements included in our 2011 Form 10-K.
For the nine month period ended September 30, 2012, in addition to the issuance of common units pursuant to our equity distribution agreement, our significant equity issuances consisted of the following:
on June 4, 2012, we issued 3,792,461 common units as our purchase price for the 50% equity ownership interest in El Paso Midstream Investment Company, LLC we acquired from KKR. For more information about this acquisition, see Note 2 "Acquisitions and Discontinued Operations—El Paso Midstream Investment Company, LLC;"
in August 2012, in connection with the drop-down transaction, we issued 4,667,575 of our common units to KMI. We valued the units at $381 million, based on the $81.52 closing market price of the common units on the New

16


York Stock Exchange on August 13, 2012. For more information on the drop-down transaction, see Note 2 "Acquisitions and Discontinued Operations—August 2012 KMI Asset Drop-Down;" and
in the third quarter of 2012, KMR issued 10,120,000 of its shares in a public offering at a price of approximately $73.50 per share, less commissions and underwriting expenses. KMR used the net proceeds received from the issuance of these 10,120,000 shares to buy additional i-units from us, and we received net proceeds of $727 million. We used the proceeds to pay a portion of the purchase price for the drop-down transaction.
Income Allocation and Declared Distributions
For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.
On August 14, 2012, we paid a cash distribution of $1.23 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended June 30, 2012. KMR, our sole i-unitholder, received a distribution of 1,578,616 i-units from us on August 14, 2012, based on the $1.23 per unit distributed to our common unitholders on that date. The distributions were declared on July 18, 2012, payable to unitholders of record as of July 31, 2012.
On August 12, 2011, we paid a cash distribution of $1.15 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended June 30, 2011. KMR, our sole i-unitholder, received a distribution of 1,701,916 i-units from us on August 12, 2011, based on the $1.15 per unit distributed to our common unitholders on that date. The distributions were declared on July 20, 2011, payable to unitholders of record as of August 1, 2011.
Our general partner’s incentive distribution that we paid in August 2012 and August 2011 (for the quarterly periods ended June 30, 2012 and 2011, respectively) was $337 million and $293 million, respectively. The increased incentive distribution to our general partner paid for the second quarter of 2012 over the incentive distribution paid for the second quarter of 2011 reflects the increase in the amount distributed per unit as well as an increase in the number of common units and i-units outstanding. Each of these two incentive distributions were reduced from what they would have been, however, by waived incentive amounts equal to $7 million related to common units issued to finance our acquisition of KinderHawk (we acquired an initial 50% ownership interest in KinderHawk in May 2010 and the remaining 50% interest in July 2011). To support our KinderHawk acquisition, our general partner agreed to waive certain incentive distribution amounts beginning with the distribution payments we made for the quarterly period ended June 30, 2010, and ending with the distribution payments we make for the quarterly period ended March 31, 2013.
For additional information about our 2011 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included in our 2011 Form 10-K and in our Current Report on Form 8-K filed May 1, 2012.
Subsequent Events
In early October 2012, we issued 269,501 of our common units for the settlement of sales made on or before September 30, 2012 pursuant to our equity distribution agreement. We received net proceeds of $22 million from the issuance of these 269,501 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
On October 17, 2012, we declared a cash distribution of $1.26 per unit for the quarterly period ended September 30, 2012. The distribution will be paid on November 14, 2012 to unitholders of record as of October 31, 2012. Our common unitholders and our Class B unitholder will receive cash. KMR will receive a distribution of 1,842,210 additional i-units based on the $1.26 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.016263) will be issued. This fraction was determined by dividing:

17


$1.26, the cash amount distributed per common unit
by
$77.478, the average of KMR’s shares’ closing market prices from October 15-26, 2012, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.

6. Risk Management    
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil. We also have exposure to interest rate risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.
Energy Commodity Price Risk Management
As of September 30, 2012, we had entered into the following outstanding commodity forward contracts to hedge our forecast energy commodity purchases and sales:
 
Net open position
long/(short)
Derivatives designated as hedging contracts
 
Crude oil
(20.5) million barrels
Natural gas fixed price
(27.6) billion cubic feet
Natural gas basis
(27.6) billion cubic feet
Derivatives not designated as hedging contracts
 
Natural gas fixed price
(0.6) billion cubic feet
As of September 30, 2012, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2016.
Interest Rate Risk Management
As of September 30, 2012, we had a combined notional principal amount of $5,525 million of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of London InterBank Offered Rate (LIBOR) plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of September 30, 2012, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.
As of December 31, 2011, we had a combined notional principal amount of $5,325 million of fixed-to-variable interest rate swap agreements. In March 2012, (i) we entered into four additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million, effectively converting a portion of the interest expense associated with our 3.95% senior notes due September 1, 2022 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (ii) two separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $200 million and converting a portion of the interest expense associated with our 7.125% senior notes terminated upon the maturity of the associated notes. In addition, (i) in June 2012, we terminated an existing fixed-to-variable interest rate swap agreement having a notional amount of $100 million, and we received proceeds of $53 million from the early termination of this swap agreement; (ii) in August 2012, we entered into an additional fixed-to-variable interest rate swap agreement having a notional principal amount of $100 million, effectively converting a portion of the interest expense associated with our 3.45% senior notes due February 15, 2023 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread; and (iii) in September 2012, a fixed-to-variable interest rate swap agreement having a combined notional principal amount of $100 million and effectively converting a portion of the interest expense

18


associated with our 5.85% senior notes terminated upon the maturity of the associated notes.
Fair Value of Derivative Contracts
The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets, or, as of September 30, 2012 only, included within “Assets held for sale.” The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of September 30, 2012 and December 31, 2011 (in millions):
Fair Value of Derivative Contracts
 
 
 
Asset derivatives
 
Liability derivatives
 
 
 
September 30,
2012
 
December 31,
2011
 
September 30,
2012
 
December 31,
2011
 
Balance sheet location
 
Fair value
 
Fair value
 
Fair value
 
Fair value
Derivatives designated as hedging contracts
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts
Current-Fair value of
 derivative contracts
 
$
58

 
$
66

 
$
(39
)
 
$
(116
)
 
Current-Assets held for
 Sale / Accrued other
 current liabilities
 
1

 

 

 

 
Non-current-Fair value
 of derivative contracts
 
52

 
39

 
(15
)
 
(39
)
Subtotal
 
 
111

 
105

 
(54
)
 
(155
)
Interest rate swap agreements
Current-Fair value of
 derivative contracts
 

 
3

 

 

 
Non-current-Fair value
 of derivative contracts
 
652

 
593

 

 

Subtotal
 
 
652

 
596

 

 

Total
 
 
763

 
701

 
(54
)
 
(155
)
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as hedging contracts
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts
Current-Fair value of
 derivative contracts
 
1

 
3

 
(2
)
 
(5
)
 
Non-current-Fair value
 of derivative contracts
 
1

 

 

 

Total
 
 
2

 
3

 
(2
)
 
(5
)
Total derivatives
 
 
$
765

 
$
704

 
$
(56
)
 
$
(160
)

The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. Our “Debt fair value adjustments” also include all unamortized debt discount/premium amounts and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. As of September 30, 2012, we had a combined unamortized debt premium amount of $378 million, and as of December 31, 2011, we had a combined debt discount amount of $24 million. As of September 30, 2012 and December 31, 2011, the unamortized premium from the termination of interest rate swap agreements totaled $500 million and $483 million, respectively, and as of September 30, 2012, the weighted average amortization period for this premium was approximately 18 years.
Effect of Derivative Contracts on the Income Statement
The following two tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three and nine months ended September 30, 2012 and 2011 (in millions):

19


Derivatives in fair value hedging
relationships
 
Location of gain/(loss) recognized
in income on derivatives
 
Amount of gain/(loss) recognized in income
on derivatives and related hedged item(a)
 
 
 
 
Three Months Ended
September 30,
 
 
Nine Months Ended
September 30,
 
 
 
 
2012
 
2011
 
 
2012
 
2011
Interest rate swap agreements
 
Interest expense
 
$
28

 
$
437

 
 
$
109

 
$
501

Total
 
 
 
$
28

 
$
437

 
 
$
109

 
$
501

 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate debt
 
Interest expense
 
$
(28
)
 
$
(437
)
 
 
$
(109
)
 
$
(501
)
Total
 
 
 
$
(28
)
 
$
(437
)
 
 
$
(109
)
 
$
(501
)
___________
(a)
Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt, which exactly offset each other as a result of no hedge ineffectiveness.

Derivatives in
cash flow hedging
relationships
 
Amount of gain/(loss)
recognized in OCI on
derivative (effective
portion)(a)
 
Location of
gain/(loss)
reclassified from
Accumulated OCI
into income
(effective portion)
 
Amount of gain/(loss)
reclassified from
Accumulated OCI
into income
(effective portion)(b)
 
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
September 30,
 
 
 
Three Months Ended
September 30,
 
 
 
Three Months Ended
September 30,
 
 
2012
 
2011
 
 
 
2012
 
2011
 
 
 
2012
 
2011
Energy commodity derivative contracts
 
$
(90
)
 
$
387

 
Revenues-Natural gas sales
 
$
2

 
$

 
Revenues-Natural gas sales
 
$

 
$

 
 
 
 
 
 
Revenues-Product sales and other
 

 
(51
)
 
Revenues-Product sales and other
 
(5
)
 
8

 
 
 
 
 
 
Gas purchases and other costs of sales
 
8

 
2

 
Gas purchases and other costs of sales
 

 

Total
 
$
(90
)
 
$
387

 
Total
 
$
10

 
$
(49
)
 
Total
 
$
(5
)
 
$
8

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended
September 30,
 
 
 
Nine Months Ended
September 30,
 
 
 
Nine Months Ended
September 30,
 
 
2012
 
2011
 
 
 
2012
 
2011
 
 
 
2012
 
2011
Energy commodity derivative contracts
 
$
99

 
$
289

 
Revenues-Natural gas sales
 
$
4

 
$
1

 
Revenues-Natural gas sales
 
$

 
$

 
 
 
 
 
 
Revenues-Product sales and other
 
(31
)
 
(203
)
 
Revenues-Product sales and other
 
(8
)
 
10

 
 
 
 
 
 
Gas purchases and other costs of sales
 
17

 
13

 
Gas purchases and other costs of sales
 

 

Total
 
$
99

 
$
289

 
Total
 
$
(10
)
 
$
(189
)
 
Total
 
$
(8
)
 
$
10

____________
(a)
We expect to reclassify an approximate $25 million gain associated with energy commodity price risk management activities and included in our Partners’ Capital as of September 30, 2012 into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)
No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, the amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred).
For each of the three and nine months ended September 30, 2012 and 2011, we recognized no material gain or loss in income from derivative contracts not designated as hedging contracts.
Credit Risks
We have counterparty credit risk as a result of our use of financial derivative contracts. Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of

20


counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.
Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
The maximum potential exposure to credit losses on our derivative contracts as of September 30, 2012 was (in millions):
 
Asset position
Interest rate swap agreements
$
652

Energy commodity derivative contracts
113

Gross exposure
765

Netting agreement impact
(39
)
Cash collateral held

Net exposure
$
726

In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of both September 30, 2012 and December 31, 2011, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil. As of September 30, 2012, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $6 million, and we reported this amount as "Restricted deposits" in our accompanying consolidated balance sheet. As of December 31, 2011, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $10 million, and we reported this amount within “Accrued other current liabilities” in our accompanying consolidated balance sheet.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating. As of September 30, 2012, we estimate that if our credit rating was downgraded one notch, we would be required to post no additional collateral to our counterparties. If we were downgraded two notches (that is, below investment grade), we would be required to post $8 million of additional collateral.

7. Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting

21


entity has the ability to access at the measurement date;
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of September 30, 2012 and December 31, 2011, based on the three levels established by the Codification. The fair values of our current and non-current asset and liability derivative contracts each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets, or, as of September 30, 2012 only, included within “Assets held for sale.” The fair value measurements in the tables below do not include cash margin deposits made by us or our counterparties, which are reported within "Restricted deposits" and “Accrued other current liabilities,” respectively, in our accompanying consolidated balance sheets (in millions).
 
Asset fair value measurements using
 
Total
 
Quoted prices in
active markets
for identical
assets (Level 1)
 
Significant other
observable
inputs (Level 2)
 
Significant
unobservable
inputs (Level 3)
As of September 30, 2012
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
113

 
$
16

 
$
88

 
$
9

Interest rate swap agreements
$
652

 
$

 
$
652

 
$

 
 
 
 
 
 
 
 
As of December 31, 2011
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
108

 
$
34

 
$
47

 
$
27

Interest rate swap agreements
$
596

 
$

 
$
596

 
$

____________
 
Liability fair value measurements using
 
Total
 
Quoted prices in
active markets
for identical
assets (Level 1)
 
Significant other
observable
inputs (Level 2)
 
Significant
unobservable
inputs (Level 3)
As of September 30, 2012
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
(56
)
 
$
(14
)
 
$
(39
)
 
$
(3
)
Interest rate swap agreements
$

 
$

 
$

 
$

 
 
 
 
 
 
 
 
As of December 31, 2011
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
(160
)
 
$
(15
)
 
$
(125
)
 
$
(20
)
Interest rate swap agreements
$

 
$

 
$

 
$

____________
(a)
Level 1 consists primarily of the New York Mercantile Exchange (NYMEX) natural gas futures. Level 2 consists primarily of over-the-counter (OTC) West Texas Intermediate swaps and OTC natural gas swaps that are settled on NYMEX. Level 3 consists primarily of West Texas Intermediate options.


22


The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three and nine months ended September 30, 2012 and 2011 (in millions):
Significant unobservable inputs (Level 3)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
Derivatives-net asset (liability)
 
 
 
 
 
 
 
Beginning of Period
$
20

 
7

 
$
7

 
$
19

Total gains or (losses):
 
 
 
 
 
 
 
Included in earnings
(3
)
 
3

 
(3
)
 
6

Included in other comprehensive income
(6
)
 
37

 

 
21

Purchases

 

 
3

 
5

Settlements
(5
)
 
(2
)
 
(1
)
 
(6
)
End of Period
$
6

 
45

 
$
6

 
$
45

 
 
 
 
 
 
 
 
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date
$
(5
)
 
$
3

 
$
(1
)
 
$
4


As of September 30, 2012, we reported our West Texas Intermediate options at fair value using Level 3 inputs due to such derivatives not having observable market prices. We determined the fair value of our West Texas Intermediate options using the Black Scholes option valuation methodology after giving consideration to a range of factors, including the prices at which the options were acquired, local market conditions, implied volatility, and trading values on public exchanges.
The significant unobservable input we use to measure the fair value of our Level 3 derivatives is implied volatility of options. We obtain the implied volatility of our West Texas Intermediate options from a third party service provider. As of September 30, 2012, this volatility ranged from 30%31% based on both historical market data and future estimates of market fluctuation. Significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
Fair Value of Financial Instruments
The estimated fair value of our outstanding debt balance as of September 30, 2012 and December 31, 2011 (both short-term and long-term), is disclosed below (in millions):
 
September 30, 2012
 
December 31, 2011
 
Carrying
Value
 
Estimated
Fair value
 
Carrying
Value
 
Estimated
Fair value
Total debt
$
19,444

 
$
20,748

 
$
13,876

 
$
14,238


We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2012 and December 31, 2011.

8. Reportable Segments
We divide our operations into five reportable business segments. These segments and their principal sources of revenues are as follows:
Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;

23


Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;
CO2—the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;
Terminals—the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and
Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.
We evaluate performance principally based on each segment’s earnings before depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third party debt costs and interest expense, unallocable interest income, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision maker organizes their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.
Financial information by segment follows (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2012
 
2011
 
2012
 
2011
Revenues
 
 
 
 
 
 
 
Products Pipelines
 
 
 
 
 
 
 
Revenues from external customers
$
386

 
$
242

 
$
940

 
$
695

Natural Gas Pipelines