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 March 31, 20132014
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.)

1001 Louisiana 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 258,605,877320,924,671 common units outstanding as of April 29, 201328, 2014.

1


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

2


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
GLOSSARY
Company Abbreviations
BOSTCO=Battleground Oil Specialty TerminalKinderHawk=KinderHawk Field Services LLC
Company LLCKMBT=Kinder Morgan Bulk Terminals, Inc.
Calnev=Calnev Pipe Line LLC
KMCO2
=
Kinder Morgan CO2 Company, L.P.
Copano=Copano Energy, L.L.C.KMEP=Kinder Morgan Energy Partners, L.P.
Eagle Ford=Eagle Ford Gathering LLCKMGP=Kinder Morgan G.P., Inc.
EP=El Paso Corporation and its majority-ownedKMI=Kinder Morgan, Inc.
and controlled subsidiariesKMLT=Kinder Morgan Liquids Terminals LLC
EPB=El Paso Pipeline Partners, L.P. and itsKMR=Kinder Morgan Management, LLC
majority-owned and controlled subsidiariesSFPP=SFPP, L.P.
EPNG=El Paso Natural Gas Company, L.L.C.TGP=Tennessee Gas Pipeline Company, L.L.C.
Unless the context otherwise requires, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our majority-owned and controlled subsidiaries, and our operating limited partnerships and their majority-owned and controlled subsidiaries.
Common Industry and Other Terms
Bcf/d=billion cubic feet per dayLLC=limited liability company
BBtu/d=billion British Thermal Units per dayMBbl/d=thousands of barrels per day
CERCLA=Comprehensive Environmental Response,MLP=master limited partnership
Compensation and Liability ActNEB=National Energy Board
CO2
=carbon dioxideNGL=natural gas liquids
CPUC=California Public Utilities CommissionNYMEX=New York Mercantile Exchange
EBDA=earnings before depreciation, depletion andNYSE=New York Stock Exchange
amortizationOTC=over-the-counter
DD&A=depreciation, depletion and amortizationPHMSA=Pipeline and Hazardous Materials Safety
DCF=distributable cash flowAdministration
EPA=United States Environmental ProtectionSEC=United States Securities and Exchange
AgencyCommission
FERC=Federal Energy Regulatory CommissionSustaining=capital expenditures which do not increase
FASB=Financial Accounting Standards Boardcapacity or throughput
GAAP=United States Generally Accepted AccountingTBtu=trillion British Thermal Units
PrinciplesWTI=West Texas Intermediate
LIBOR=London Interbank Offered Rate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.


3

Table of Contents

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

See Information Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 (2013 Form 10-K) for a more detailed description of factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our 2013 Form 10-K. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We plan to provide updates to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.



4

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions Except Per Unit Amounts)
(Unaudited)
 Three Months Ended
March 31,
 2013 2012
Revenues   
Natural gas sales$735
 $584
Services1,188
 761
Product sales and other738
 503
Total Revenues2,661
 1,848
    
Operating Costs, Expenses and Other   
Costs of sales957
 580
Operations and maintenance384
 306
Depreciation, depletion and amortization328
 239
General and administrative134
 107
Taxes, other than income taxes74
 50
Total Operating Costs, Expenses and Other1,877
 1,282
    
Operating Income784
 566
    
Other Income (Expense)   
Earnings from equity investments83
 65
Amortization of excess cost of equity investments(2) (2)
Interest expense, net(199) (135)
Gain on sale of investments in Express pipeline system225
 
Other, net4
 1
Total Other Income (Expense)111
 (71)
    
Income from Continuing Operations Before Income Taxes895
 495
    
Income Tax Expense(101) (15)
    
Income from Continuing Operations794
 480
    
Discontinued Operations (Notes 1 and 2)   
Income from operations of FTC Natural Gas Pipelines disposal group
 50
Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value(2) (322)
Loss from Discontinued Operations(2) (272)
    
Net Income792
 208
    
Net Income Attributable to Noncontrolling Interests(9) (2)
    
Net Income Attributable to Kinder Morgan Energy Partners, L.P.$783
 $206
    
Calculation of Limited Partners’ Interest in Net (Loss) Income   
Attributable to Kinder Morgan Energy Partners, L.P.:   
Income from Continuing Operations$785
 $475
Less: Pre-acquisition income from operations of drop-down asset group allocated to General Partner(19) 
Add: Drop-Down asset group severance expense allocated to General Partner2
 
Less: General Partner’s remaining interest(402) (321)
Limited Partners’ Interest366
 154
Add: Limited Partners’ interest in discontinued operations(2) (266)
Limited Partners��� Interest in Net Income (Loss)$364
 $(112)
    
Limited Partners’ Net Income (Loss) per Unit - basic and diluted:   
Income from Continuing Operations$0.97
 $0.46
Loss from Discontinued Operations
 (0.79)
Net Income (Loss) - basic and diluted$0.97
 $(0.33)
    
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit376
 338
    
Per Unit Cash Distribution Declared$1.30
 $1.20
    
The accompanying notes are an integral part of these consolidated financial statements.

3

Table of Contents


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)
(Unaudited)
 Three Months Ended
March 31,
 2013 2012
Net Income$792
 $208
    
Other Comprehensive Income (Loss):   
Change in fair value of derivatives utilized for hedging purposes(41) (114)
Reclassification of change in fair value of derivatives to net income(7) 31
Foreign currency translation adjustments(43) 38
Adjustments to pension and other postretirement benefit plan liabilities, net of tax1
 (1)
Total Other Comprehensive Loss(90) (46)
    
Comprehensive Income702
 162
Comprehensive Income Attributable to Noncontrolling Interests(8) (1)
Comprehensive Income Attributable to Kinder Morgan Energy Partners, L.P.$694
 $161
    
The accompanying notes are an integral part of these consolidated financial statements.

4

Table of Contents


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions)
 March 31,
2013
 December 31, 2012(a)
ASSETS(Unaudited)  
Current assets   
Cash and cash equivalents$736
 $529
Accounts receivable, net of allowance1,085
 1,114
Inventories352
 338
Fair value of derivative contracts33
 55
Assets held for sale32
 211
Other current assets124
 130
Total Current assets2,362
 2,377
    
Property, plant and equipment, net22,584
 22,330
Investments1,880
 1,864
Goodwill5,412
 5,417
Other intangibles, net1,123
 1,142
Fair value of derivative contracts552
 634
Deferred charges and other assets1,239
 1,212
Total Assets$35,152
 $34,976
    
LIABILITIES AND PARTNERS’ CAPITAL   
Current liabilities   
Current portion of debt$1,127
 $1,155
Accounts payable983
 1,091
Accrued interest184
 327
Fair value of derivative contracts49
 21
Accrued other current liabilities851
 653
Total Current liabilities3,194
 3,247
    
Long-term liabilities and deferred credits   
Long-term debt   
Outstanding16,829
 15,907
Debt fair value adjustments1,586
 1,698
Total Long-term debt18,415
 17,605
Deferred income taxes254
 249
Fair value of derivative contracts11
 13
Other long-term liabilities and deferred credits1,044
 1,100
Total Long-term liabilities and deferred credits19,724
 18,967
    
Total Liabilities22,918
 22,214
Commitments and contingencies (Notes 3 and 9)

  
Partners’ Capital   
Common units5,137
 4,723
Class B units13
 14
i-units3,676
 3,564
General partner3,008
 4,026
Accumulated other comprehensive income79
 168
Total Kinder Morgan Energy Partners, L.P. Partners’ Capital11,913
 12,495
Noncontrolling interests321
 267
Total Partners’ Capital12,234
 12,762
Total Liabilities and Partners’ Capital$35,152
 $34,976
The accompanying notes are an integral part of these consolidated financial statements.
____________
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Unit Amounts)
(Unaudited)
 Three Months Ended
March 31,
 2014 2013
Revenues   
Natural gas sales$1,096
 $735
Services1,458
 1,231
Product sales and other1,098
 695
Total Revenues3,652
 2,661
    
Operating Costs, Expenses and Other   
Costs of sales1,638
 957
Operations and maintenance450
 384
Depreciation, depletion and amortization401
 328
General and administrative153
 134
Taxes, other than income taxes83
 74
Other income, net(6) 
Total Operating Costs, Expenses and Other2,719
 1,877
    
Operating Income933
 784
    
Other Income (Expense)   
Earnings from equity investments72
 83
Amortization of excess cost of equity investments(3) (2)
Interest, net(238) (199)
Gain on sale of investments in Express pipeline system (Note 2)
 225
Other, net6
 4
Total Other Income (Expense)(163) 111
    
Income from Continuing Operations Before Income Taxes770
 895
    
Income Tax Expense(16) (101)
    
Income from Continuing Operations754
 794
    
Loss from Discontinued Operations (Note 2 )
 (2)
    
Net Income754
 792
    
Net Income Attributable to Noncontrolling Interests(8) (9)
    
Net Income Attributable to KMEP$746
 $783
    
Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP:   
Income from Continuing Operations attributable to KMEP$746
 $785
Less: Pre-acquisition income from operations of March 2013 drop-down asset group allocated to
General Partner (Note 1)

 (19)
Add: Drop-down asset group’s severance expense allocated to General Partner (Note 1)5
 2
Less: General Partner’s remaining interest(452) (402)
Limited Partners’ Interest299
 366
Add: Limited Partners’ Interest in Discontinued Operations
 (2)
Limited Partners’ Interest in Net Income$299
 $364
    
Limited Partners’ Net Income per Unit:   
Income from Continuing Operations$0.67
 $0.97
Loss from Discontinued Operations
 
Net Income$0.67
 $0.97
    
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit448
 376
    
Per Unit Cash Distribution Declared for the Period$1.38
 $1.30
    
The accompanying notes are an integral part of these consolidated financial statements.

(a)Retrospectively adjusted as discussed in Note 1.

5

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
(Unaudited)
 Three Months Ended
March 31,
 2013 2012
Cash Flows From Operating Activities   
Net Income$792
 $208
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, depletion and amortization328
 246
Amortization of excess cost of equity investments2
 2
Gain from the sale of investments in Express pipeline system (Note 2)(225) 
Loss from the sale of discontinued operations and the remeasurement of
 FTC Natural Gas Pipelines disposal group to fair value (Note 2)
2
 322
Earnings from equity investments(83) (87)
Distributions from equity investments82
 80
Changes in components of working capital:   
Accounts receivable21
 83
Inventories(13) (77)
Other current assets24
 41
Accounts payable(161) (61)
Accrued interest(143) (162)
Accrued other current liabilities208
 105
Rate reparations, refunds and other litigation reserve adjustments15
 
Other, net(103) (42)
Net Cash Provided by Operating Activities746
 658
    
Cash Flows From Investing Activities   
Payment to KMI for drop-down asset group (Note 2)(988) 
Acquisitions of assets and investments(4) (30)
Capital expenditures(552) (353)
Proceeds from sale of investments in Express pipeline system403
 
Contributions to equity investments(40) (49)
Distributions from equity investments in excess of cumulative earnings19
 43
Other, net(9) 16
Net Cash Used in Investing Activities(1,171) (373)
    
Cash Flows From Financing Activities   
Issuance of debt2,699
 2,420
Payment of debt(1,809) (2,160)
Debt issue costs(7) (6)
Proceeds from issuance of common units385
 124
Contributions from noncontrolling interests65
 2
Pre-acquisition contributions and distributions from KMI to drop-down asset group35
 
Distributions to partners and noncontrolling interests:   
Common units(326) (270)
Class B units(7) (6)
General Partner(388) (307)
Noncontrolling interests(9) (7)
Net Cash Provided by (Used in) Financing Activities638
 (210)
    
Effect of Exchange Rate Changes on Cash and Cash Equivalents(6) 7
    
Net increase in Cash and Cash Equivalents207
 82
Cash and Cash Equivalents, beginning of period529
 409
Cash and Cash Equivalents, end of period$736
 $491
    
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)
(Unaudited)
 Three Months Ended
March 31,
 2014 2013
Net Income$754
 $792
    
Other Comprehensive Income (Loss):   
Change in fair value of derivatives utilized for hedging purposes(56) (41)
Reclassification of change in fair value of derivatives to net income18
 (7)
Foreign currency translation adjustments(79) (43)
Adjustments to pension and other postretirement benefit plan liabilities(2) 1
Total Other Comprehensive (Loss)(119) (90)
    
Comprehensive Income635
 702
Comprehensive Income Attributable to Noncontrolling Interests(7) (8)
Comprehensive Income Attributable to KMEP$628
 $694
    
The accompanying notes are an integral part of these consolidated financial statements.


6

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
(Unaudited)
 Three Months Ended
March 31,
 2013 2012
Noncash Investing and Financing Activities   
Assets acquired or liabilities settled by the issuance of common units$108
 $7
Increase in accrual for construction costs$51
 $13
    
Supplemental Disclosures of Cash Flow Information   
Cash paid during the period for interest (net of capitalized interest)$318
 $272
Cash paid during the period for income taxes$3
 $4
    
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions)
 March 31,
2014
 December 31,
2013
 (Unaudited)  
ASSETS   
Current assets   
Cash and cash equivalents$347
 $404
Accounts receivable, net1,455
 1,511
Inventories381
 393
Natural gas imbalance receivables172
 68
Other current assets328
 292
Total current assets2,683
 2,668
    
Property, plant and equipment, net28,558
 27,405
Investments2,263
 2,233
Goodwill6,606
 6,547
Other intangibles, net2,380
 2,414
Deferred charges and other assets1,468
 1,497
Total Assets$43,958
 $42,764
    
    
LIABILITIES AND PARTNERS’ CAPITAL   
Current liabilities   
Current portion of debt$1,243
 $1,504
Accounts payable1,444
 1,537
Accrued interest205
 371
Accrued contingencies581
 529
Other current liabilities726
 636
Total current liabilities4,199
 4,577
    
Long-term liabilities and deferred credits   
Long-term debt   
Outstanding19,610
 18,410
Debt fair value adjustments1,235
 1,214
Total long-term debt20,845
 19,624
Deferred income taxes277
 285
Other long-term liabilities and deferred credits1,014
 1,057
Total long-term liabilities and deferred credits22,136
 20,966
    
Total Liabilities26,335
 25,543
Commitments and contingencies (Notes 3 and 9)

  
Partners’ Capital   
Common units9,863
 9,459
Class B units3
 6
i-units4,312
 4,222
General partner3,083
 3,081
Accumulated other comprehensive (loss) income(85) 33
Total KMEP Partners’ Capital17,176
 16,801
Noncontrolling interests447
 420
Total Partners’ Capital17,623
 17,221
Total Liabilities and Partners’ Capital$43,958
 $42,764
    
The accompanying notes are an integral part of these consolidated financial statements.


7

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
(Unaudited)
 Three Months Ended
March 31,
 2014 2013
Cash Flows From Operating Activities   
Net Income$754
 $792
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, depletion and amortization401
 328
Amortization of excess cost of equity investments3
 2
Gain on sale of investments in Express pipeline system (Note 2)
 (225)
Earnings from equity investments(72) (83)
Distributions from equity investment earnings54
 82
Changes in components of working capital, net of the effects of acquisitions:   
Accounts receivable22
 21
Inventories10
 (13)
Other current assets9
 24
Accounts payable(3) (161)
Accrued interest(165) (143)
Accrued contingencies and other current liabilities49
 208
Other, net12
 (86)
Net Cash Provided by Operating Activities1,074
 746
    
Cash Flows From Investing Activities   
Payment to KMI for March 2013 drop-down asset group (Note 1)
 (988)
Business acquisitions (Note 2)(960) 
Acquisitions of assets-other(25) (4)
Loans to related party(17) 
Capital expenditures(809) (552)
Proceeds from sale of investments in Express pipeline system
 403
Contributions to investments(35) (40)
Distributions from equity investments in excess of cumulative earnings15
 19
Natural gas storage and natural gas and liquids line-fill21
 10
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs19
 (3)
Other, net(10) (16)
Net Cash Used in Investing Activities(1,801) (1,171)
    
Cash Flows From Financing Activities   
Issuance of debt4,498
 2,699
Payment of debt(3,569) (1,809)
Debt issue costs(10) (7)
Proceeds from issuance of common units619
 385
Proceeds from issuance of i-units6
 
Contributions from noncontrolling interests32
 65
Pre-acquisition contributions from KMI to March 2013 drop-down asset group
 35
Distributions to partners and noncontrolling interests(895) (730)
Other, net(1) 
Net Cash Provided by Financing Activities680
 638
    
Effect of Exchange Rate Changes on Cash and Cash Equivalents(10) (6)
    
Net (decrease) increase in Cash and Cash Equivalents(57) 207
Cash and Cash Equivalents, beginning of period404
 529
Cash and Cash Equivalents, end of period$347
 $736
    
Noncash Investing and Financing Activities   
Assets acquired or liabilities settled by the issuance of common units (Note 1)$
 $108
    
Supplemental Disclosures of Cash Flow Information   
Cash paid during the period for interest (net of capitalized interest)$373
 $318
Cash paid during the period for income taxes$2
 $3
    
The accompanying notes are an integral part of these consolidated financial statements.

8

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In Millions, Except Units)
(Unaudited)
 Three Months Ended March 31,
 2014 2013
 Units Amount Units Amount
Common units:       
Beginning Balance312,791,561
 $9,459
 252,756,425
 $4,723
Net income

 211
 

 246
Units issued as consideration in the acquisition of assets
 
 1,249,452
 108
Units issued for cash8,133,110
 619
 4,600,000
 385
Distributions

 (426) 

 (326)
Other adjustments

 
 

 1
Ending Balance320,924,671
 9,863
 258,605,877
 5,137
        
Class B units: 
  
  
  
Beginning Balance5,313,400
 6
 5,313,400
 14
Net income

 4
 

 6
Distributions

 (7) 

 (7)
Ending Balance5,313,400
 3
 5,313,400
 13
        
i-Units: 
  
  
  
Beginning Balance125,323,734
 4,222
 115,118,338
 3,564
Net income

 84
 

 112
Units issued for cash76,100
 6
 
 
Distributions2,237,258
 
 1,804,596
 
Ending Balance127,637,092
 4,312
 116,922,934
 3,676
        
General partner: 
  
  
  
Beginning Balance

 3,081
 

 4,026
Net income

 447
 

 419
Distributions

 (450) 

 (388)
Drop-Down acquisition (Note 1)

 
 

 (1,051)
Reimbursed severance expense allocated from KMI

 5
 

 1
Other adjustments

 
 

 1
Ending Balance

 3,083
 

 3,008
        
Accumulated other comprehensive income (loss): 
  
  
  
Beginning Balance

 33
 

 168
Other comprehensive loss  (118)   (89)
Ending Balance

 (85) 

 79
        
Total KMEP Partners’ Capital453,875,163
 17,176
 380,842,211
 11,913
        
Noncontrolling interests:       
Beginning Balance

 420
 

 267
Net income

 8
 

 9
Contributions

 32
 

 65
Distributions

 (12) 

 (9)
Drop-Down acquisition (Note 1)

 
 

 (10)
Other comprehensive loss  (1)   (1)
Ending Balance

 447
 

 321
        
Total Partners’ Capital453,875,163
 $17,623
 380,842,211
 $12,234
        
The accompanying notes are an integral part of these consolidated financial statements.


9

Table of Contents

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
Kinder Morgan Energy Partners, L.P.KMEP is a Delaware limited partnership formed in August 1992.  We are a leading pipeline transportation and energy storage company in North America, managing a diversified portfolio of energy transportation 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., our operating limited partnerships and their majority-owned and controlled subsidiaries.storage assets. We own an interest in or operate approximately 44,00052,000 miles of pipelines and 180 terminals, and we conduct our business through five reportable business segments (described further in Note 7). WeOur common units trade on the New York Stock ExchangeNYSE under the symbol “KMP.”
Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxidecondensate, CO2 and other products, and our terminals store petroleum products, ethanol 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.
Kinder Morgan, Inc.KMI and Kinder Morgan G.P., Inc.
Kinder Morgan, Inc.,KMI, 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. 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.
Calnev. KMI’s common stock trades on the New York Stock ExchangeNYSE under the symbol “KMI.”
As of March 31, 20132014, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by Kinder Morgan Management, LLCits subsidiary KMR (discussed following)below), an approximate 13.0%11.5% interest in us.
Effective In addition, as of May 25, 2012March 31, 2014, KMI acquired all of the outstanding shares of El Paso Corporation, a Delaware corporation referred to as EP in this report. KMI’s acquisition of EP created one of the largest energy companies in the United States. As a result, KMI owns a 41%40% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P.EPB.
Kinder Morgan Management, LLCKMR
Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company.LLC. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a duty to manage us in a manner beneficial to our unitholders. KMR’s shares representing limited liability companyLLC interests trade on the New York Stock ExchangeNYSE under the symbol “KMR.” As of March 31, 20132014, KMR, through its sole ownership of our i-units, owned approximately30.7%28.1% of all of our outstanding limited partner units (all(which are in the form of our i-units that are issued only to KMR).
More information about the entities referred to above and the delegation of control agreement is contained in our Annual Report on2013 Form 10-K10-K. For a more complete discussion of our related party transactions with the entities referred to above, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the year endedassets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 December 31, 2012. In this report, we referRelated Party Transactions” to our Annual Report on Form 10-K for the year endedconsolidated financial statements included in our December 31, 20122013 as our 2012 Form 10-K.
Basis of Presentation
General
WeOur reporting currency is in U.S. dollars, and all references to dollars are U.S. dollars, except where stated otherwise.  Canadian dollars are designated as C$.

Our accompanying consolidated financial statements include our accounts, and the accounts of Copano and our operating limited partnerships and Copano’s majority-owned and controlled subsidiaries, and we have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission.SEC. These rules and

10

Table of Contents

regulations conform to the accounting principles contained in the FinancialFASB’s Accounting Standards Board’s Accounting Standards Codification.Codification, the single source of GAAP. Under such rules and

8

Table of Contents

regulations, all significant intercompany items have been eliminated in consolidation. Additionally, 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 unaudited 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, andperiods. In addition, certain amounts from prior periods have been reclassified to conform to the current presentation.presentation (including reclassifications between “Services” and “Product sales and other” within the “Revenues” section of our accompanying consolidated statements of income). 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 20122013 Form 10-K.
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 8 “Related Party Transactions—Asset Acquisitions,Transactions,” KMI is not liable for, and its assets are not available to satisfy, theour obligations of us and/or our subsidiariessubsidiaries’ obligations, 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.
March 2013 KMI Asset Drop-Down
Effective March 1, 2013,, we acquired from KMI the remaining 50% ownership interest we did not already own in both the El Paso Natural Gas pipeline systemEPNG and the EP midstream assets for an aggregate consideration of approximately $1.7$1.7 billion (including our proportional 50%share of assumed debt borrowings as of March 1, 2013). In this report, we refer to this acquisition of assets from KMI as the March 2013 drop-down transaction; the combined group of assets acquired from KMI effective March 1, 2013 as the March 2013 drop-down asset group; the El Paso Natural Gas pipeline system or El Paso Natural Gas Company, L.L.C. as EPNG; and the EP midstream assets orof Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the EP midstream assets. We acquired our initial 50% ownership interest in EPNG from KMI effective August 1, 2012, and we acquired our initial 50% ownership interest in the EP midstream assets from an investment vehicle affiliated with Kohlberg Kravis Roberts & Co. L.P. (together with its affiliates,, referred to as KKR)KKR, effective June 1, 2012. Prior to our acquisition from KMI,the March 2013 drop-down transaction, we accounted for our initial 50% interestownership interests in both EPNG and the EP midstream assets (the March 1, 2013 drop-down asset group) under the equity method of accounting.
KMI acquired a 100% ownership interest in EPNG and a 50% ownership interestall of the assets included in the midstream assetsMarch 2013 drop-down asset group as part of its May 25, 2012 acquisition of EP, on May 25, 2012 (discussed above).and KMI accounted for its EP acquisition of the drop-down asset group under the acquisition method of accounting, and weaccounting. We, however, accounted for the March 2013 drop-down transaction as a combinationcombinations of entities under common control. WeAccordingly, we prepared our consolidated financial statements to reflect the transfer of the remaining 50% ownership interests in EPNG and the midstream assetsMarch 2013 drop-down asset group from KMI to us as if such transferstransfer had taken place on the date when both EPNG and the midstream assetsMarch 2013 drop-down asset group met the accounting requirements for entities under common control—May 25, 2012 for EPNG, and June 1, 2012 for the EP midstream assets. Specifically, we (i) consolidateconsolidated our now 100% investments investment in both EPNG and the midstream assets having recognizedMarch 2013 drop-down asset group as of the effective dates of common control, recognizing the acquired assets and assumed liabilities at KMI’s carrying value as of the effective dates of common control (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 acquired as an adjustment to our Partners’ Capital (specifically, as an adjustment to our general partner’s and our noncontrolling interests’ capital interests); and (iii) retrospectively adjusted our consolidated financial statements, for any date after the effective dates of common control.
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 to our general partner:
the earnings of the March 2013 drop-down asset group for the periods beginning on the effective dates of common control (described above) and ending March 1, 2013 (and (we refer to these earnings as “pre-acquisition” earnings and we reported this amountthese earnings separately as “Pre-acquisition income from operations of drop-

9

Table of Contents

down asset group allocated to General Partner” within the Calculation of Limited Partners’ Interest in Net Income (Loss) section of our accompanying consolidated statementMarch 2013 drop-down asset group allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP” section of our accompanying consolidated statements of income for the three months ended March 31, 2013); and
incremental severance expense related to KMI’s acquisition of EP and allocated to us from KMI (and we reported this amount separately as “Drop-down asset group severance expense allocated to General Partner” within the Calculation of Limited Partners’ Interest in Net Income (Loss) section of our accompanying consolidated statement of income for the three months ended March 31, 2013). TheKMI. This severance expense allocated to us was associated with both the March 2013 drop-down asset group and the assets we acquired from KMI effective August 1, 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense.

11

Table of Contents

(pursuant to the drop-down) from KMI effective August 1, 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense. Furthermore, we reported this expense separately as “Drop-down asset group’s severance expense allocated to General Partner” within the “Calculation of Limited Partners’ Interest in Net Income Attributable to KMEP” section of our accompanying consolidated statements of income for each of the three months ended March 31, 2014 and 2013.

For all periods beginning after our acquisition date of March 1, 2013, we allocated our earnings (including the earnings from the March 2013 drop-down asset group) to all of our partners according to our partnership agreements.
FTC Natural Gas Pipelines Disposal Group – Discontinued Operations
Effective November 1, 2012, we sold 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 to Tallgrass Development, LP (now known as Tallgrass Energy Partners, LP) (Tallgrass) for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In this report, we refer to this combined group of assets as our FTC Natural Gas Pipelines disposal group. The sale of our FTC Natural Gas Pipelines disposal group satisfied the terms of a March 15, 2012 agreement between KMI and the U.S. Federal Trade Commission (FTC) to divest certain of our assets in order to receive regulatory approval for KMI’s EP acquisition. For more information about the presentation of our FTC Natural Gas Pipelines disposal group as discontinued operations, see Note 2 “Summary of Significant Accounting Policies—Basis of Presentation—FTC Natural Gas Pipelines Disposal Group - Discontinued Operations” to our consolidated financial statements included in our 2012 Form 10-K.agreement.
Goodwill
We evaluate goodwill for impairment on May 31 of each year.  There were no impairment charges resulting from our May 31, 20122013 impairment testing, and no event indicating an impairment has occurred subsequent to that date.

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.

2. Acquisitions and Divestitures    

Acquisitions

March 2013 KMI Asset Drop-DownAmerican Petroleum Tankers and State Class Tankers

Effective January 17, 2014, we acquired American Petroleum Tankers (APT) and State Class Tankers (SCT) for aggregate consideration of $960 million in cash, subject to purchase price adjustments (the APT acquisition). Our general partner has agreed to waive incentive distribution amounts of $13 million for 2014, $19 million for 2015 and $6 million for 2016 to facilitate the transaction.

APT is engaged in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade. APT’s primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Navy. The vessels’ time charters have an average remaining term of approximately four years, with renewal options to extend the initial terms by an average of two years. APT’s vessels are operated by Crowley Maritime Corporation.

SCT has commissioned the construction of four medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity. The SCT vessels are scheduled to be delivered in 2015 and 2016 and are being constructed by General Dynamics’ NASSCO shipyard. We expect to invest approximately $214 million to complete the construction of the vessels. Upon delivery, the SCT vessels will be operated pursuant to long-term time charters with a major integrated oil company. Each of the time charters has an initial term of five years, with renewal options to extend the initial term by up to three years. Our APT acquisition complements and extends our existing crude oil and refined products transportation business, and all of the acquired assets are included in our Terminals business segment.

As discussed above in Noteof March 31, 2014, our preliminary purchase price allocation related to our APT acquisition, as adjusted to date, is as follows (in millions). Our evaluation of the assigned fair values is ongoing and subject to adjustment.
Preliminary Purchase Price Allocation: 
Current assets$2
Property, plant and equipment887
Goodwill68
Other assets3
Total assets acquired960
Cash consideration$960


12


The “Goodwill” intangible asset amount represents the future economic benefits expected to be derived from this acquisition that are not assignable to other individually identifiable, separately recognizable assets acquired. We believe the primary items that generated the goodwill are the value of the synergies created by expanding our non-pipeline liquids handling operations, and we expect the entire amount to be deductible for tax purposes.

Other

Effective May 1, 2013General”, we acquired the drop-down asset group from KMI effective March 1, 2013all. Our consideration to KMI consisted of (i)Copano’s outstanding units for a total purchase price of approximately $988 million5.2 billion in cash; (ii)(including assumed debt and all other assumed liabilities). The transaction was a 1,249,452100% unit for unit transaction with an exchange ratio of 0.4563 of our common units (valuedfor each Copano common unit. We issued 43,371,210 of our common units valued at $1083,733 million basedas consideration for the Copano acquisition (based on the $86.7286.08 closing market price of a common unit on the New York Stock ExchangeNYSE on the MarchMay 1, 2013 issuance date); and (iii) .$557 million in assumed debt (consisting of 50% of the outstanding principal amount of EPNG’s debt borrowings as of March
Effective June 1, 2013, 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 directorswe acquired certain oil and on our behalf by the audit committeesgas properties, rights, 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.
The EPNG natural gas pipeline system collectively consists of both the 10,200-mile El Paso Natural Gas pipeline system and the 500-mile Mojave pipeline system. It has a design capacity of approximately 5.6 billion cubic feet per day of natural gas, and transports natural gas from the San Juan, Permian and Anadarko basins to California, other western

10


states, Texas and northern Mexico. EPNG also provides up to 44 billion cubic feet of underground working natural gas storage capacity. The midstream assets include both the Altamont natural gas gathering, processing and treatingrelated assets located in the Uinta Basin in Utah, and the Camino Real natural gas andGoldsmith Landreth San Andres oil gathering system locatedfield unit in the Eagle Ford shale formation in South Texas. We included the drop-down asset group in our Natural Gas Pipelines reportable business segment.
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 an initial 50% ownership interest in EPNGPermian Basin of West Texas from KMILegado Resources LLC for an aggregate consideration of approximately $298 million, consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations).

$6.2 billion. For additional information about this acquisition,our Copano and Goldsmith Landreth acquisitions (including our preliminary purchase price allocations as of December 31, 2013), see Note 2 “Summary of Significant Accounting Policies—Basis of Presentation—August 2012 KMI Asset Drop-Down” and Note 3 “Acquisitions and Divestitures—August 2012 KMI Asset Drop-Down”Business Combinations and Acquisitions of Investments” to our consolidated financial statements included in our 20122013 Form 10-K. In this report, we refer to the Tennessee Gas natural gas pipeline system or our wholly-owned subsidiary Tennessee Gas Pipeline Company, L.L.C. as TGP.

Pro Forma Information

The following summarized unaudited pro forma consolidated income statement information for the three months ended March 31, 2012,2013 assumes that our acquisitionacquisitions of TGP(i) APT, (ii) Copano and our initial 50% ownership interest in EPNG(iii) the Goldsmith Landreth oil field unit had occurred as of January 1, 20122013. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed our acquisition of TGP and our initial 50% interest in EPNGthese acquisitions as of January 1, 20122013, or the results that will be attained in the future. Amounts presented below are in millions, except for the per unit amounts:

 
Pro Forma
Three Months Ended March 31, 2012
 (Unaudited)
Revenues$2,116
Income from Continuing Operations$579
Loss from Discontinued Operations$(272)
Net Income$307
Net Income Attributable to Noncontrolling Interests$(2)
Net Income Attributable to Kinder Morgan Energy Partners, L.P.$305
  
Limited Partners’ Net Income (Loss) per Unit: 
Income from Continuing Operations$0.70
Loss from Discontinued Operations(0.76)
Net Loss$(0.06)

Copano Energy, L.L.C.

On January 29, 2013, we and Copano Energy, L.L.C., referred to in this report as Copano, announced a definitive agreement whereby we will acquire all of Copano’s outstanding units, including convertible preferred units, for a total purchase price of approximately $5 billion, including the assumption of debt. The transaction, which has been approved by the board of directors of each of KMR, our general partner, and its delegate, as well as the board of directors of Copano, will be a 100% unit for unit transaction with an exchange ratio of 0.4563 of our common units for each Copano unit. The transaction is subject to customary closing conditions, regulatory approvals, and a vote of the Copano unitholders; however, TPG Advisors VI, Inc., Copano’s largest unitholder, has agreed to support the transaction and we expect the transaction to close in early May 2013.
Copano is a midstream natural gas company that provides comprehensive services to natural gas producers, including natural gas gathering, processing, treating and natural gas liquids fractionation. Copano owns an interest in or operates approximately 6,900 miles of pipelines with 2.7 billion cubic feet per day of natural gas transportation capacity, and also owns nine natural gas processing plants with more than 1 billion cubic feet per day of natural gas processing capacity and

11


315 million cubic feet per day of natural gas treating capacity. Its operations are located primarily in Texas, Oklahoma and Wyoming. Most of the acquired assets will be included in our Natural Gas Pipelines business segment.
 Pro Forma
 Three Months Ended
March 31, 2013
 (Unaudited)
Revenues$3,211
Income from Continuing Operations766
Loss from Discontinued Operations(2)
Net Income764
Net Income Attributable to Noncontrolling Interests(9)
Net Income Attributable to KMEP755
  
Limited Partners’ Net Income per Unit: 
Income from Continuing Operations$0.79
Net Income$0.79

Divestitures
FTC Natural Gas Pipelines Disposal Group – Discontinued Operations
As described above in Note 1 “General—Basis of Presentation,” we began accounting for our FTC Natural Gas Pipelines disposal group as discontinued operations in the first quarter of 2012 (prior to KMI’s sale announcement, we included the disposal group in our Natural Gas Pipelines business segment). During that quarter, we also remeasured the disposal group's net assets to reflect our initial assessment of its fair value as a result of the FTC mandated sale requirement, and based on this remeasurement, we recognized a $322 million loss. We reported this loss amount separately as Loss on sale 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 three months ended March 31, 2012. The final consideration was trued up in the first quarter of 2013 resulting in a $2 million additional loss recorded as Loss on sale and the remeasurement of FTC Natural Gas Pipelines disposal group to fair value.” As a result of our remeasurement of net assets to fair value and the sale of net assets, we recognized a combined $829 million loss for the year ended December 31, 2012.
Summarized financial information for the disposal group is as follows (in millions):

 Three Months Ended March 31, 2012
Operating revenues$71
Operating expenses(37)
Depreciation and amortization(7)
Earnings from equity investments22
Interest income and Other, net1
Income from operations of FTC Natural Gas Pipelines disposal group$50

Express Pipeline System

Effective March 14, 2013, we sold both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. forWe received net cash proceeds of $403402 million (after paying $1 million in cash. We recordedthe second quarter of 2013 for both a pre-tax gainfinal working capital settlement and certain transaction related selling expenses), and we reported the $403 million in proceeds received in the first quarter of 2013 separately as “Proceeds from sale of investments in Express pipeline system” within the investing section of our

13


accompanying consolidated statements of cash flows. Additionally, we recognized a combined $225 million pre-tax gain with respect to this transaction,sale in the first quarter of 2013, and we reported this gain amount separately as Gain“Gain on sale of investments in Express pipeline system” inon our accompanying consolidated statementstatements of income for the three months ended March 31, 2013.income. We also recorded an income tax expense of $84 million related to this gain amount,on sale for the three month period, and we included this expense within Income Tax Expense” in our accompanying consolidated statement of income for the three months ended March 31, 2013.Expense.” As of the date of sale, our equity investment in Express totaled $67 million and our note receivable due from Express totaled $110 million.

PriorFTC Natural Gas Pipelines Disposal Group – Discontinued Operations
As discussed in our 2013 Form 10-K, we sold our FTC Natural Gas Pipelines disposal group to Tallgrass Energy Partners, LP (now known as Tallgrass Development, LP) (Tallgrass) effective November 1, 2012. We and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group in the first quarter of 2013, and based on this true up, we (i) accounted for our equity investment under the equity method of accounting; (ii) accounted for our debt investment under the historical amortized cost method of accounting; and (iii) included the financial results of the Express pipeline system within our Kinder Morgan Canada business segment. As of December 31, 2012, our equity and debt investments in Express totaled $65recognized an additional $2 million and $114 million, respectively, and we included the combined $179 million amount within “Assets held for sale” on our accompanying consolidated balance sheet as of that date.



loss.
3. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income using the effective interest rate method. The following table summarizesprovides detail on the carrying valueprincipal amount of our outstanding debt excluding our debt fair value adjustments, as of March 31, 20132014 and December 31, 20122013. The table amounts exclude all debt fair value adjustments, including debt discounts and premiums (in millions):.

12

 March 31,
2014
 December 31,
2013
KMEP borrowings:   
Senior notes, 2.65% through 9.00%, due 2014 through 2044(a)$17,100
 $15,600
Commercial paper borrowings(b)419
 979
Credit facility due May 1, 2018(c)
 
Subsidiary borrowings (as obligor):   
TGP - Senior Notes, 7.00% through 8.375%, due 2016 through 20371,790
 1,790
EPNG - Senior Notes, 5.95% through 8.625%, due 2017 through 20321,115
 1,115
Copano - Senior Notes, 7.125%, due April 1, 2021332
 332
Other miscellaneous subsidiary debt97
 98
Total debt20,853
 19,914
Less: Current portion of debt(d)(1,243) (1,504)
Total long-term debt(e)$19,610
 $18,410
Table of Contents

 March 31,
2013
 December 31,
2012
Current portion of debt(a)$1,127
 $1,155
Long-term portion of debt16,829
 15,907
Carrying value of debt(b)$17,956
 $17,062
__________
(a)
AsAll of our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to March 31, 2013100% and December 31, 2012, includes commercial paper borrowings of $595 million and $621 million, respectively.the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium.
(b)
As of March 31, 2014 and December 31, 2013, the average interest rates on our outstanding commercial paper borrowings were 0.26% and 0.28%, respectively. The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during the first three months of 2014, and in the near term, we expect that our short-term liquidity and financing needs will be met primarily through borrowings made under our commercial paper program.
(c)See “—Credit Facilities” below.
(d)Amounts include outstanding commercial paper borrowings, discussed above in footnote (b).
(e)
Excludes debt fair value adjustments. As of March 31, 20132014 and December 31, 20122013, our “Debt fair value adjustments increased our debt balances by $1,5861,235 million and $1,6981,214 million, respectively. In addition to all unamortized debt discount/premium amounts and purchase accounting on our debt balances, our debt fair value adjustments also include (i) amounts associated with the offsetting entry for hedged debt; and (ii) any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see Note 5 “Risk Management—Debt Fair Value of Derivative Contracts.Adjustments.

Credit Facilities
Changes in our outstanding debt, excluding debt fair value adjustments, during the three months endedAs of both March 31, 20132014 are summarized as follows (in millions):

Debt borrowings Interest rate Increase / (decrease) Cash received / (paid)
Issuances and assumptions      
Senior notes due September 1, 2023(a) 3.50% $600
 $598
Senior notes due March 1, 2043(a) 5.00% 400
 398
Commercial paper variable
 1,689
 1,689
Kinder Morgan Altamont LLC credit facility due August 2, 2014(b) variable
 14
 14
Total increases in debt   $2,703
 $2,699
       
Repayments and other      
Commercial paper variable
 (1,715) (1,715)
Kinder Morgan Altamont LLC credit facility due August 2, 2014(b) variable
 (92) (92)
Kinder Morgan Texas Pipeline, L.P. - senior notes due January 2, 2014 5.23% (2) (2)
Total decreases in debt   $(1,809) $(1,809)
__________
(a)
On February 28, 2013, we completed a public offering of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 3.50% notes due September 1, 2023 and $400 million of 5.00% notes due March 1, 2043. We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $991 million, and we used the proceeds to pay a portion of the purchase price for our drop-down transaction and to reduce theand December 31, 2013, we had no borrowings under our commercial paper program.
(b)
Our subsidiary, Kinder Morgan Altamont LLC maintains an unsecured revolving bank credit facility that matures on August 2, 2014. Effective March 31, 2013, Kinder Morgan Altamont LLC reduced the amount available for borrowing under this credit facility from $95 million to approximately $1 million. In addition, in February 2013, prior to our March 1, 2013 acquisition date, we and KMI each contributed $45 million to repay the outstanding $90 million borrowings under this credit facility, and following this repayment, Kinder Morgan Altamont LLC had no outstanding debt.
We also maintain a $2.22.7 billionfive-year senior unsecured revolving credit facility that matures Julymaturing May 1, 2016. Our2018. Borrowings under our revolving credit facility can be amended to provide for borrowings of up to $2.5 billion, and borrowings under the facility can be used for

14


general partnership purposes and as a backup for our commercial paper program. There were noSimilarly, borrowings under our commercial paper program reduce the borrowings allowed under our credit facility as of facility.

March 31, 2013 or as of December 31, 2012. We had, as of March 31, 20132014, $1,3952,079 million of borrowing capacity available under our credit facility. The amount available for borrowing under our credit facility was reduced by a combined amount of $805621 million, consisting of$595419 million of commercial paper borrowings and $210202 million of letters

13

Table of Contents

of credit, consisting of (i) a $100 million letter of credit that supports certain proceedings with the California Public Utilities CommissionCPUC involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $8584 million in three letters of credit that support tax-exempt bonds; and (iii) a combined $2518 million in other letters of credit supporting other obligations of us and our subsidiaries.
For additional information regarding
Changes in Debt
On January 15, 2014, in anticipation of our APT acquisition, we entered into a short-term unsecured liquidity facility with us as borrower, and UBS as administrative agent. This liquidity facility provided for borrowings of up to $1.0 billion from a syndicate of financial institutions and was scheduled to mature on July 15, 2014. Additionally, in conjunction with the establishment of this liquidity facility, we increased our commercial paper program to provide for the issuance of up to $3.7 billion (up from $2.7 billion). We made no borrowings under this liquidity facility, and after receiving the cash proceeds from both our February 2014 public offering of senior notes (described following) and our February 2014 public offering of common units (described in Note 4 “Partners’ Capital—Equity Issuances”), we terminated the liquidity facility and decreased our commercial paper program to again provide for the issuance of up to $2.7 billion.

On February 24, 2014, we completed a public offering of a total $1.5 billion in principal amount of senior notes in two separate series. We received net proceeds of $743 million from the offering of $750 million in principal amount of 3.50% senior notes due March 1, 2021, and$739 million from the offering of $750 million in principal amount of 5.50% senior notes due March 1, 2044. We used the proceeds from our February 2014 debt facilities and for information onoffering to reduce the borrowings under our contingent debt agreements, see Note 8 “Debt” and Note 12 “Commitments and Contingent Liabilities”commercial paper program (by reducing the incremental commercial paper borrowings we made in January 2014 to fund our consolidated financial statements included in our 2012 Form 10-K.APT acquisition).

4. Partners’ Capital

Limited Partner Units
As of March 31, 20132014 and December 31, 20122013, our Partners’ Capital included the following limited partner units:
March 31,
2013
 December 31,
2012
March 31,
2014
 December 31,
2013
Common units:      
Held by third parties236,318,422
 231,718,422
298,637,216
 290,504,106
Held by KMI and affiliates (excluding our general partner)20,563,455
 19,314,003
20,563,455
 20,563,455
Held by our general partner1,724,000
 1,724,000
1,724,000
 1,724,000
Total Common units258,605,877
 252,756,425
320,924,671
 312,791,561
Class B units(a)5,313,400
 5,313,400
5,313,400
 5,313,400
i-units(b)116,922,934
 115,118,338
127,637,092
 125,323,734
Total limited partner units380,842,211
 373,188,163
453,875,163
 443,428,695
_________
(a)
As of both March 31, 20132014 and December 31, 20122013, all of our Class B units were held by a wholly-owned subsidiary of KMI.  The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange.NYSE.

(b)
As of both March 31, 20132014 and December 31, 20122013, all of our i-units were held by KMR.  Our i-units are a separate class of limited partner interests in us and are not publicly traded.  In accordance with its limited liability companyKMR’s LLC agreement, KMR’s activities are restricted to being a limited partner in us, and to controlling and managing our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries.  Through the combined effect of the provisions in our partnership agreement and the provisions of KMR’s limited liability companyLLC agreement, the number of outstanding KMR shares and the number of our i-units will at all times be equal. 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.


15

Table of Contents

The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s right to receive incentive distribution rights.distributions. Our general partner has an effective 2% interest in us, excluding its right to receive incentive distributions.
Changes in Partners’ Capital
For each of the three month periods ended March 31, 2013 and 2012, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income are

14

Table of Contents

summarized as follows (in millions):
 Three Months Ended March 31,
 2013 2012
 KMP 
Noncontrolling
Interests
 Total KMP Noncontrolling interests Total
Beginning Balance$12,495
 $267
 $12,762
 $7,508
 $96
 $7,604
Units issued for cash385
 
 385
 124
 
 124
Units issued as consideration in the acquisition of assets(a)108
 
 108
 7
 
 7
Distributions paid in cash(721) (9) (730) (583) (7) (590)
Adjustments to capital due to acquisitions from KMI(a)(1,051) (10) (1,061) 
 
 
Noncash compensation expense allocated from KMI(b)1
 
 1
 
 
 
Cash contributions
 65
 65
 
 2
 2
Other adjustments2
 
 2
 
 2
 2
Comprehensive income694
 8
 702
 161
 1
 162
Ending Balance$11,913
 $321
 $12,234
 $7,217
 $94
 $7,311
__________
(a)
Amounts relate to the drop-down transaction, described in Note 2 “Acquisitions and Divestitures—Acquisitions—March 2013 KMI Asset Drop-Down.” We determined that this drop-down transaction constituted a combination of 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). We then recognized the difference between the carrying value of the assets acquired and liabilities assumed as an adjustment to our Partners’ Capital (these asset, liability and partner capital adjustments are all included in our December 31, 2012 balance sheet). In the first quarter of 2013, we paid to KMI $988 million in cash, issued to KMI 1,249,452 common units valued at $108 million, and recognized a $1,061 million decrease in our Partners’ Capital. As of March 31, 2013, the combined carrying value of the assets we acquired and the liabilities we assumed (including acquired cash balances and the contributions and distributions we received from KMI for periods prior to our acquisition date of March 1, 2013) totaled $1,168 million. In combination, the inclusion of the acquired net assets and the consideration paid to KMI resulted in a non-cash increase of $72 million in our Partners’ Capital as of March 31, 2013. The increase to Partners’ Capital consisted of a $71 million increase in our general partner’s 1% general partner capital interest in us, and a $1 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)We do not have any obligation, nor did we pay any amounts related to this expense. For further information about this expense, see Note 1 “General—Basis of Presentation—March 2013 KMI Asset Drop-Down.”

During each of the three month periods ended March 31, 2013 and 2012, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.
Equity Issuances
For the three month period ended March 31, 20132014, our significant equity issuances consisted of the following:
on February 26, 2013,24, 2014, we issued, in a public offering, 4,600,0007,935,000 of our common units at a price of $86.3578.32 per unit, less commissions and underwriting expenses. We received net proceeds after deducting the underwriter discount, of $385603 million for the issuance of these 4,600,0007,935,000 common units, and used the proceeds to reduce the borrowings under our commercial paper program (by reducing the incremental borrowings we made under our commercial paper program in January 2014 to fund our APT acquisition);
in January 2014, we issued 198,110 of our common units pursuant to our equity distribution agreements with UBS (to settle sales made on or before December 31, 2013). We received net proceeds from the issuance of these common units of $16 million, and we used the proceeds to pay a portion ofreduce the purchase price for the drop-down transaction;borrowings under our commercial paper program; and
On March 1, 2013, in connection with the drop-down transaction,January 2014, we issued 1,249,45276,100 of our common unitsi-units to KMI.KMR (to settle sales made on or before December 31, 2013). We valued the units atreceived net proceeds of $1086 million, based on for the $86.72 closing market priceissuance of a common unit onthese i-units, and we used the New York Stock Exchange on March 1, 2013. For more information onproceeds to reduce the drop-down transaction, see Note 2 “Acquisitions and Divestitures—Acquisitions—March 2013 KMI Asset Drop-Down.”borrowings under our commercial paper program.

Income Allocation and Declared DistributionsAllocations
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

15


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.
Partnership Distributions
The following table provides information about our distributions for each of the three month periods ended March 31, 20132014 and 20122013 (in millions except per unit and i-Uniti-unit distributions amounts):

 Three Months Ended March 31,
 2013 2012
Per unit cash distribution declared$1.30
 $1.20
Per unit cash distribution paid(a)$1.29
 $1.16
Cash distributions paid to all partners(b)(c)$730
 $590
i-Unit distributions made to KMR(d)1,804,596
 1,464,145
General Partner’s incentive distribution(e):   
Declared$398
 $319
Paid(a)(c)$384
 $302
 Three Months Ended
March 31,
 2014 2013
Per unit cash distribution declared for the period$1.38
 $1.30
Per unit cash distribution paid in the period$1.36
 $1.29
Cash distributions paid in the period to all partners(a)(b)$895
 $730
i-unit distributions made in the period to KMR(c)2,237,258
 1,804,596
General Partner’s incentive distribution(d):   
Declared for the period(e)$449
 $398
Paid in the period(b)(c)(f)$445
 $384
___________________
(a)Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.

(b)Consisting of our common and Class B unitholders, our general partner and noncontrolling interests.

(c)(b)
The quarter-to-quarter increaseperiod-to-period increases in distributions paid primarily reflect the increaseincreases in amounts distributed per unit as well as the issuance of additional units; however, the overall increase in distributions paid was partially offset by decreases of $7 million and $8 million, in the incentive distribution we paid to our general partner in the first quarters of 2013 and 2012, respectively. The decreases represented waived incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk Field Services LLC acquisition.  Beginning with our distribution payments for the quarterly period ended June 30, 2010, and ending with our distribution payments for the quarterly period ended March 31, 2013, our general partner agreed not to take certain incentive distributions related to our acquisition of KinderHawk Field Services LLC.  For more information about our KinderHawk acquisition, see Note 3 “Acquisitions and Divestitures—Business Combinations and Acquisitions of Investments—(3) KinderHawk Field Services LLC (1 of 2)” and “—(6) KinderHawk Field Services LLC and EagleHawk Field Services LLC (2 of 2)” to our consolidated financial statements included in our 2012 Form 10-K.
units.

(d)(c)
Under the terms of our partnership agreement, we agreed that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units.  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 will 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.  If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns. Based on the preceding, the i-units we distributed were based on the $1.29$1.36 and $1.16$1.29 per unit paid to our common unitholders during the first quarters of 20132014 and 20122013, respectively.

(e)(d)
Incentive distribution does not include the general partner’s initial 2% distribution of available cash.

16


(e)
2014 amount includes a decrease of $30 million for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition, and a decrease of $3 million for waived general partner incentive amounts related to common units issued to finance a portion of our January 2014 APT acquisition. 2013 amount includes a decrease of $4 million for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.
(f)2014 amount includes a decrease of $25 million for waived general partner incentive amounts related to common units issued to finance our May 2013 Copano acquisition. 2013 amount includes a decrease of $7 million for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition.

For additional information about our 2012 partnership distributions, see Note 16 “Litigation, Environmental11 “Related Party Transactions—Partnership Interests and Other Contingencies” and Note 17 “Regulatory Matters”Distributions” to our consolidated financial statements included in our 20122013 Form 10-K.
Subsequent Events
On April 17, 2013,16, 2014, we declared a cash distribution of $1.301.38 per unit for the quarterly period ended March 31, 20132014. The distribution will be paid on May 15, 20132014 to unitholders of record as of April 29, 2013.30, 2014. Our common unitholders and our Class B unitholder will receive cash. KMR will receive a distribution of 1,726,9522,386,814 additional i-units based on the

16


the$1.301.38 distribution per common unit. For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.014770)(0.018700) will be issued. This fraction was determined by dividing:
$1.301.38, the cash amount distributed per common unit
by
$88.01573.796, the average of KMR’s shares’ closing market prices from April 11-24, 2013,11-25, 2014, 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.NYSE.

5. Risk Management    
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquidsNGL 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 March 31, 20132014, we had entered into the following outstanding commodity forward contracts to hedge our forecastforecasted energy commodity purchases and sales:
 
Net open position
long/(short)
Derivatives designated as hedging contracts  
Crude oil fixed price(21.4)(24.0)million barrelsMMBbl
Natural gas fixed price(33.9)(23.0)billion cubic feetBcf
Natural gas basis(34.4)(23.0)billion cubic feetBcf
Derivatives not designated as hedging contracts  
Crude oil fixed price(0.1)(0.7)million barrelsMMBbl
Crude oil basis(3.6)(0.7)million barrelsMMBbl
Natural gas fixed price(2.0)(13.1)billion cubic feetBcf
Natural gas basis12.2(9.1)billion cubic feetBcf
NGL fixed price(1.0)MMBbl

As of March 31, 20132014, 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 20162018.

Interest Rate Risk Management

As of both March 31, 2013 and December 31, 20122014, we had a combined notional principal amount of $5,5255,175 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)LIBOR plus a spread. All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of March 31, 20132014, the

17


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 throughMarch 15, 2035.2035.

As of December 31, 2013, we had a combined notional principal amount of $4,675 million of fixed-to-variable interest rate swap agreements. In February 2014, we entered into four separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million. These agreements effectively convert a portion of the interest expense associated with our 3.50% senior notes due March 1, 2021, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.

Fair Value of Derivative Contracts
The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets. The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of March 31, 20132014 and December 31, 20122013 (in millions):

17


Fair Value of Derivative Contracts
 Asset derivatives Liability derivatives Asset derivatives Liability derivatives
 March 31,
2013
 December 31,
2012
 March 31,
2013
 December 31,
2012
 March 31,
2014
 December 31,
2013
 March 31,
2014
 December 31,
2013
Balance sheet location Fair value Fair value Fair value Fair valueBalance 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
 $19
 $42
 $(45) $(18)Other current assets/(Other current liabilities) $13
 $18
 $(51) $(33)
Non-current-Fair value
 of derivative contracts
 37
 40
 (8) (11)Deferred charges and other assets/(Other long-term liabilities and deferred credits) 22
 58
 (13) (30)
Subtotal 56
 82
 (53) (29) 35
 76
 (64) (63)
Interest rate swap agreements
Current-Fair value of
 derivative contracts
 7
 9
 
 
Other current assets/(Other current liabilities) 105
 76
 
 
Non-current-Fair value
 of derivative contracts
 515
 594
 (3) (1)Deferred charges and other assets/(Other long-term liabilities and deferred credits) 151
 141
 (94) (116)
Subtotal 522
 603
 (3) (1) 256
 217
 (94) (116)
Total 578
 685
 (56) (30) 291
 293
 (158) (179)
                
Derivatives not designated as hedging contracts                
Energy commodity derivative contracts
Current-Fair value of
 derivative contracts
 7
 4
 (4) (3)Other current assets/(Other current liabilities) 6
 4
 (9) (5)
Non-current-Fair value
 of derivative contracts
 
 
 
 (1)
Total 7
 4
 (4) (4) 6
 4
 (9) (5)
Total derivatives(a) $585
 $689
 $(60) $(34)
Total derivatives $297
 $297
 $(167) $(184)
___________
(a)
As of March 31, 2013 and December 31, 2012, we presented the fair value of our derivative contracts on a gross basis on our accompanying consolidated balance sheets.  If we had elected to net derivative contracts subject to master netting agreements as of March 31, 2013 and December 31, 2012, the impact would have reduced our derivative assets and liabilities by $18 million and $17 million, respectively.  As of March 31, 2013 and December 31, 2012, we had cash margin deposits associated with our derivative contracts posted with counterparties of $21 million and $5 million, respectively, that would have additionally reduced our derivative liabilities.

Debt Fair Value Adjustments

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, purchase accounting on our debt balances, and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. TheseAs of March 31, 2014 and December 31, 2013, these fair value adjustments to our debt balances included (i) $624629 million and $638645 million at March 31, 2013 and December 31, 2012, respectively, associated with fair value adjustments to our debt previously recorded in purchase accounting; (ii) $519162 million and $602101 million at March 31, 2013 and December 31, 2012, respectively, associated with the offsetting entry for hedged debt; (iii) $476501 million and $488517 million at March 31, 2013 and December 31, 2012, respectively, associated with unamortized premium from the termination of interest rate swap agreements; and offset by (iv) $3357 million and $3049 million at March 31, 2013 and December 31, 2012, respectively, associated with unamortized debt discount amounts. As of March 31, 20132014, the weighted-average amortization period of the unamortized premium from the termination of the interest rate swaps was approximately 1816 years.


18


Effect of Derivative Contracts on the Income Statement
The following twothree tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three months ended March 31, 20132014 and 20122013 (in millions):

18


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)
 
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
March 31,
 Three Months Ended
March 31,
 2013 2012 2014 2013
Interest rate swap agreements Interest expense$(83) $(113) Interest expense$61
 $(83)
Total $(83) $(113) $61
 $(83)
    
Fixed rate debt Interest expense$83
 $113
 Interest expense$(61) $83
Total $83
 $113
 $(61) $83
___________
(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)
 
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
March 31,
 Three Months Ended
March 31,
 Three Months Ended
March 31,
 Three Months Ended
March 31,
 Three Months Ended
March 31,
 Three Months Ended
March 31,
 2013 2012 2013 2012 2013 2012 2014 2013 2014 2013 2014 2013
Energy commodity derivative contracts $(41) $(114) Revenues-Natural gas sales $
 $
 Revenues-Natural gas sales $
 $
 $(56) $(41) Revenues-Natural gas sales $(10) $
 Revenues-Natural gas sales $
 $
     Revenues-Product sales and other 7
 (29) Revenues-Product sales and other (3) (3)     Revenues-Product sales and other (9) 7
 Revenues-Product sales and other (5) (3)
     Gas purchases and other costs of sales 
 (2) Gas purchases and other costs of sales 
 
     Costs of sales 1
 
 Costs of sales 
 
Total $(41) $(114) Total $7
 $(31) Total $(3) $(3) $(56) $(41) Total $(18) $7
 Total $(5) $(3)
____________
(a)
We expect to reclassify an approximate $1430 million loss associated with energy commodity price risk management activities and included in our Partners’ Capital as of March 31, 20132014 into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, the amountsAmounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchasepurchases actually occurred).
Derivatives not designated as hedging contractsLocation of gain/(loss) recognized in income on derivativeAmount of gain/(loss) recognized in income on derivatives
  Three Months Ended
March 31,
  2013 2012
Natural gas derivative contractsRevenues-Natural gas sales$
 $
Crude oil derivative contractsRevenues-Product sales and other4
 
Total $4
 $
Derivatives not designated as accounting hedgesLocation of gain/(loss) recognized in income on derivativesAmount of gain/(loss) recognized in income on derivatives
  Three Months Ended
March 31,
  2014 2013
Energy commodity derivative contractsRevenues-Natural gas sales$(7) $
 Revenues-Product sales and other(7) 4
 Costs of sales10
 
 Other expense (income)(2) 
Total $(6) $4

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

19


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);condition; (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-counterOTC swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with a number of parties, all of which have investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
The maximum potential exposure to credit losses on our derivative contracts as of March 31, 2013 was as follows (in millions):
 Asset position
Interest rate swap agreements$522
Energy commodity derivative contracts63
Gross exposure585
Netting agreement impact(18)
Cash collateral held
Net exposure$567
In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of both March 31, 20132014 and December 31, 20122013, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquidsNGL and crude oil. As of March 31, 2013 and December 31, 2012, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $21 million and $5 million, respectively, and we included these deposit amounts within Other current assets” in our accompanying consolidated balance sheets.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating. As of March 31, 20132014, 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 $1325 million of additional collateral.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive (loss) income” within “Partners’ Capital” in our consolidated balance sheets. Changes in the components of our Accumulated other comprehensive (loss) income” for each of the three months ended March 31, 20132014 and 2013 are summarized as follows (in millions):
 
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjs.
 
Total
Accumulated other
comprehensive
income/(loss)
Balance as of December 31, 2013$24
 $(4) $13
 $33
Other comprehensive (loss) income before reclassifications(56) (78) (2) (136)
Amounts reclassified from accumulated other comprehensive income18
 
 
 18
Net current-period other comprehensive (loss) income(38) (78) (2) (118)
Balance as of March 31, 2014$(14) $(82) $11
 $(85)
______________

20



Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjs.
 
Total
Accumulated other
comprehensive
income/(loss)
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
 
Foreign
currency
translation
adjustments
 
Pension and
other
postretirement
liability adjs.
 
Total
Accumulated other
comprehensive
income/(loss)
Balance as of December 31, 2012$66
 $132
 $(30) $168
$66
 $132
 $(30) $168
Other comprehensive income before reclassifications(40) (43) 1
 (82)
Other comprehensive (loss) income before reclassifications(40) (43) 1
 (82)
Amounts reclassified from accumulated other comprehensive income(7) 
 
 (7)(7) 
 
 (7)
Net current-period other comprehensive income(47) (43) 1
 (89)
Net current-period other comprehensive (loss) income(47) (43) 1
 (89)
Balance as of March 31, 2013$19
 $89
 $(29) $79
$19
 $89
 $(29) $79

6. 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 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 March 31, 20132014 and December 31, 20122013, based on the three levels established by the Codification. The fair valuesAlso, certain of our current and non-current asset and liability derivative contracts are each reported separatelysubject to master netting agreements. The following tables present our derivative contracts subject to such netting agreements as “Fair value of derivative contracts” in the respective sections of our accompanying consolidated balance sheets. The fair value measurements in the tables below do not include cash margin deposits made by us, which are reported within March 31, 2014Other current assets” in our accompanying consolidated balance sheets and December 31, 2013 (in millions).:
Asset fair value measurements using
Balance Sheet asset
fair value measurements using
 Amounts not offset in the Balance Sheet Net Amount
Total 
Quoted prices in
active markets
for identical
assets (Level 1)
 
Significant other
observable
inputs (Level 2)
 
Significant
unobservable
inputs (Level 3)
Level 1 Level 2 Level 3 Gross Amount Financial Instruments Cash Collateral Held(b)
As of March 31, 2013       
As of March 31, 2014             
Energy commodity derivative contracts(a)$63
 $2
 $57
 $4
$6
 $29
 $6
 $41
 $(30) $
 $11
Interest rate swap agreements$522
 $
 $522
 $
$
 $256
 $
 $256
 $(44) $
 $212
       
As of December 31, 2012       
As of December 31, 2013             
Energy commodity derivative contracts(a)$86
 $3
 $76
 $7
$4
 $46
 $30
 $80
 $(44) $
 $36
Interest rate swap agreements$603
 $
 $603
 $
$
 $217
 $
 $217
 $(28) $
 $189

21


____________
Liability fair value measurements using
Balance Sheet liability
fair value measurements using
 Amounts not offset in the Balance Sheet Net Amount
Total 
Quoted prices in
active markets
for identical
liabilities (Level 1)
 
Significant other
observable
inputs (Level 2)
 
Significant
unobservable
inputs (Level 3)
Level 1 Level 2 Level 3 Gross Amount Financial Instruments Cash Collateral Held(c)
As of March 31, 2013       
As of March 31, 2014             
Energy commodity derivative contracts(a)$(57) $(17) $(39) $(1)$(14) $(50) $(9) $(73) $30
 $22
 $(21)
Interest rate swap agreements$(3) $
 $(3) $
$
 $(94) $
 $(94) $44
 $
 $(50)
       
As of December 31, 2012       
As of December 31, 2013             
Energy commodity derivative contracts(a)$(33) $(3) $(26) $(4)$(6) $(31) $(31) $(68) $44
 $17
 $(7)
Interest rate swap agreements$(1) $
 $(1) $
$
 $(116) $
 $(116) $28
 $
 $(88)
____________
(a)Level 1 consists primarily of New York Mercantile Exchange (NYMEX)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.WTI swaps. Level 3 consists primarily of West Texas IntermediateWTI options, WTI basis swaps, NGL options and West Texas Intermediate basisNGL swaps.
(b)Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets.
(c)Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current assets” on our accompanying consolidated balance sheets.

The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three months ended March 31, 20132014 and 20122013 (in millions):

Significant unobservable inputs (Level 3)
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
Derivatives-net asset (liability)      
Beginning of Period$3
 $7
$(1) $3
Total gains or (losses):      
Included in earnings6
 2
1
 6
Included in other comprehensive income(1) (22)(1) (1)
Purchases
 3
Settlements(5) 7
(2) (5)
End of Period$3
 $(3)$(3) $3
   
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets held at the reporting date$
 $2
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date$3
 $

As of March 31, 20132014, our Level 3 derivative assets and liabilities consisted primarily of West Texas Intermediate (WTI)WTI options, WTI basis swaps, NGL options and WTI basisNGL swaps, where a significant portion of fair value is calculated from underlying market data that is not readily available.observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in our management’s best estimate of fair value. For each of the three months ended March 31, 2013 and 2012, our Level 3 activity was not material.

Fair Value of Financial Instruments
The estimated fair value of our outstanding debt balance as of March 31, 20132014 and December 31, 20122013 (both short-term and long-term and including debt fair value adjustments), is disclosed below (in millions):

22


 March 31, 2013 December 31, 2012
 
Carrying
Value
 
Estimated
Fair value
 
Carrying
Value
 
Estimated
Fair value
Total debt$19,542
 $21,105
 $18,760
 $20,439
 March 31, 2014 December 31, 2013
 
Carrying
Value
 
Estimated
Fair value
 
Carrying
Value
 
Estimated
Fair value
Total debt$22,088
 $22,935
 $21,128
 $21,550

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 20132014 and December 31, 20122013.


22


7. Reportable Segments
We divide our operations intooperate in five reportable business segments. These segments and their principal sources of revenues are as follows:
Natural Gas Pipelines—the sale, transport, processing, treating, fractionation, storage and gathering of natural gas;gas and NGL;
CO2—the production, sale and saletransportation of crude oil from fields in the Permian Basin of West Texas and the production, transportation and marketing of carbon dioxideCO2 used as a flooding medium for recovering crude oil from mature oil fields;
Products Pipelines—the transportation and terminaling of refined petroleum products including(including gasoline, diesel fuel and jet fuel, natural gas liquids,fuel), NGL, crude oil and condensate, and bio-fuels;
Terminals—the transportation, transloading and storing of refined petroleum products, crude oil, 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 and the State of Washington and the Rocky Mountains and Central regions of the United States.Washington. As further described in Note 2,3, Kinder Morgan Canada divested its interest in the Express pipeline system effective March 14, 2013.

We evaluate performance principally based on each segment’s earnings before depreciation, depletion and amortization expensesEBDA (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 organizesmakers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies.
Financial information by segment follows (in millions):
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
Revenues      
Natural Gas Pipelines(a)$1,369
 $794
   
Revenues from external customers$2,175
 $1,369
Intersegment revenues1
 
CO2
429
 417
483
 429
Products Pipelines454
 223
534
 454
Terminals337
 341
391
 337
Kinder Morgan Canada72
 73
69
 72
Total segment revenues3,653
 2,661
Less: Total intersegment revenues(1) 
Total consolidated revenues$2,661
 1,848
$3,652
 $2,661


23


Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
Segment earnings before depreciation, depletion, amortization
and amortization of excess cost of equity investments(b)
   
Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments(a)   
Natural Gas Pipelines(a)$557
 $222
$719
 $557
CO2
342
 334
363
 342
Products Pipelines185
 176
208
 185
Terminals186
 187
214
 186
Kinder Morgan Canada(c)(b)193
 50
48
 193
Total segment earnings before DD&A1,463
 969
Total segment depreciation, depletion and amortization(328) (239)
Segment EBDA1,552
 1,463
Total segment DD&A expense(401) (328)
Total segment amortization of excess cost of investments(2) (2)(3) (2)
General and administrative expenses(134) (107)
General and administrative expense(153) (134)
Interest expense, net of unallocable interest income(202) (139)(239) (202)
Unallocable income tax expense(3) (2)(2) (3)
Loss from discontinued operations(2) (272)
 (2)
Total consolidated net income$792
 $208
$754
 $792
March 31,
2013
 December 31,
2012
March 31,
2014
 December 31,
2013
Assets      
Natural Gas Pipelines$19,375
 $19,403
$25,517
 $25,721
CO2
2,376
 2,337
2,996
 2,954
Products Pipelines4,965
 4,921
5,650
 5,488
Terminals5,350
 5,123
7,183
 6,124
Kinder Morgan Canada1,688
 1,903
1,622
 1,678
Total segment assets33,754
 33,687
42,968
 41,965
Corporate assets(d)(c)1,398
 1,289
990
 799
Total consolidated assets$35,152
 $34,976
$43,958
 $42,764
____________
(a)
The increase in the 2013 amount versus the 2012 amount reflects our acquisition of the drop-down asset group from KMI effective March 1, 2013 (discussed further in Note 2 “Acquisitions and Discontinued Operations).
(b)Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).income, net. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(c)(b)
2013 amount includes a $141 million increase in earnings from the after-taxgain on the sale of our investments in the Express pipeline system.
(d)(c)Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to debt fair value adjustments.

8. Related Party Transactions
Notes Receivable
Plantation Pipe Line Company
We and ExxonMobil have a term loan agreement covering a note receivable due from Plantation Pipe Line Company. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $49 million as of both March 31, 2013 and December 31, 2012. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year,

24


with a final principal payment of $45 million (for our portion of the note) due on July 20, 2016. We included $1 million of our note receivable balance within “Other current assets,” on our accompanying consolidated balance sheets as of both March 31, 2013 and December 31, 2012, and we included the remaining outstanding balance within “Deferred charges and other assets.”
Asset Acquisitions
From time to time in the ordinary course of business, we buy and sell pipelineassets and related services from KMI and its subsidiaries.  Such transactions are conducted in accordance with all applicable laws and regulations and on an arms’ length basis consistent with our policies governing such transactions.  In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; (ii) TransColorado Gas Transmission Company LLC from KMI in November 2004; (iii) TGP and 50% of EPNG from KMI in August 2012; and (iv) the remaining 50% ownership interest in EPNG and the EP midstream assets from KMI in March 2013, KMI has agreed to indemnify us and our general partner with respect to approximately $5.9 billion of our debt.debt as of March 31, 2014. KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.

Other
24

Generally, KMR makes all decisions relating to the management and control
The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of duty. The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.
For a more complete discussion of our related party transactions, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the assets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 Related Party Transactions” to our consolidated financial statements included in our 2012 Form 10-K.

9. Litigation, Environmental and Other Contingencies
We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Partnership. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Partnership. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
Federal Energy Regulatory Commission Proceedings

25


The tariffs and rates charged by SFPP L.P. (SFPP) and El Paso Natural Gas Company, LLC (EPNG)EPNG are subject to a number of ongoing proceedings at the FERC. A substantial portion of our legal reserves relate to these FERC cases and the CPUC cases described below them. 
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers.  In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA).  If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward.  These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.  The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance we may include in our rates.  With respect to all of the SFPP proceedings at the FERC, we estimate that the shippers are seeking approximately $20$20 million in annual rate reductions and approximately $100$100 million in refunds.  However, applying the principles of several recent FERC decisions in SFPP cases, as applicable, to other pending cases would result in substantially lower rate reductions and refunds than those sought by the shippers.  We do not expect refunds in these cases to have an impact on our distributions to our limited partners.
EPNG
The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (“Opinion 517”)(Opinion 517) in May 2012 and2012. EPNG implemented certain aspects of that decision. The FERC subsequently issueddecision and believes it has an order requiring EPNG to decrease its ratesappropriate reserve related to the 2010 rate casefindings in accordance with Opinion 517. EPNG has sought rehearing on that order as well as Opinion 517. With respect to the 2010 rate case, the presiding administrative law judgeFERC issued an initialits decision (Opinion 528) on October 17, 2013. The FERC ordered EPNG to file within 60 days of issuance of Opinion 528 revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC has ordered additional proceedings concerning one of the issues in June 2012.  This initial decisionOpinion 528. EPNG has filed for rehearing on certain issues in Opinion 528. We have evaluated all recent decisions and believe our reserve is currently being reviewed by the FERC.  EPNG is pursuing settlement with its shippers in both open rate cases and believes the accruals established for these matters are adequate.appropriate.

California Public Utilities Commission Proceedings

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

On May 26, 2011, the CPUC issued a decision in several intrastate rate cases involving SFPP and a number of its shippers (the “Long” cases).  The decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance, allocation of environmental expenses, and refund liability which we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines. On March 8, 2012, the CPUC issued another

25


decision related to the Long cases. This decision largely reflected the determinations made on May 26, 2011, including the denial of an income tax allowance for SFPP. The CPUC’s order denied SFPP’s request for rehearing of the CPUC’s income tax allowance treatment, while granting requested rehearing of various, other issues relating to SFPP’s refund liability and staying the payment of refunds until resolution of the outstanding issues on rehearing. On March 23, 2012, SFPP filed a petition for writ of review in the California Court of Appeals, seeking a court order vacating the CPUC’s determination that SFPP is not entitled to recover an income tax allowance in its intrastate rates. The Court has granted review with respect todenied SFPP’s petition, and oral arguments were held on April 25, 2013.October 16, 2013, the California Supreme Court declined SFPP’s request for further review. SFPP is currently assessing the precise impact of the now final state rulings denying SFPP an income tax allowance and is awaiting CPUC decisions that will determine the impact related to the denial of an income tax allowance.

On April 6, 2011, in proceedings unrelated to the above-referenced CPUC dockets, a CPUC administrative law judge issued a proposed decision (Bemesderfer case) substantially reducing SFPP’s authorized cost of service and ordering SFPP to pay refunds from May 24, 2007 to the present of revenues collected in excess of the authorized cost of service. The proposed decision was subsequently withdrawn, and the presiding administrative law judge is expected to reissue a proposed decision at some indeterminate time in the future.

On January 30, 2012, SFPP filed an application reducing its intrastate rates by approximately 7%. This matter remains

26


pending before the CPUC. The matter is scheduled for hearing in April, 2013,CPUC, with a decision expected in the third or fourth quarter of 2014.

On July 19, 2013, Calnev filed an application with the CPUC requesting a 36% increase in its intrastate rates. A decision from the CPUC approving the requested rate increase was issued on November 14, 2013.

On November 27, 2013, the CPUC issued its Order to Show Cause directing SFPP to demonstrate whether or not the CPUC should require immediate refund payments associated with various pending SFPP rate matters. Subsequently, the CPUC issued an order directing SFPP and its shippers to engage in mandatory settlement discussions. On April 3, 2014, the CPUC issued its ruling suspending proceedings in all pending SFPP matters until October 1, 2014 or the date upon which SFPP and its shippers inform the CPUC that SFPP and its shippers have reached settlement of all pending matters or have failed to do so. If the matter is not settled, a decision addressing, if not resolving, all pending SFPP rate matters at the CPUC is anticipated in the first quarter of 2015.

Based on our review of these CPUC proceedings and the shipper comments thereon, we estimate that the shippers are requesting approximately $375$400 million in reparation payments and approximately $30$30 million in annual rate reductions.  The actual amount of reparations will be determined through settlement negotiations or further proceedings at the CPUC and, potentially, the California CourtCPUC. As of Appeals. WeMarch 31, 2014, we believe our legal reserve is adequate such that the appropriate applicationresolution of the income tax allowance and correctionspending CPUC matters will not have a material adverse impact on our business, financial position or results of errors in law and fact should result in a considerably lower amount.  Weoperations. Furthermore, we do not expect any reparations that we would pay in these mattersthis matter to have a material impact on ourthe per unit cash distributions we expect to pay to our limited partners.
Copano Shareholders’ Litigation

Three putative class action lawsuits are currently pending in connection with our proposed merger with Copano: (i) Schultes v. Copano Energy, L.L.C., et al. (Case No. 06966), in the District Court of Harris County, Texas, which is referred to as the Texas State Action; (ii) Bruen v. Copano Energy, L.L.C., et al. (Case No. 4:13-CV-00540) in the United States District Courtpartners for the Southern District of Texas, which is referred to as the Texas Federal Action; and (iii) In re Copano Energy, L.L.C. Shareholder Litigation, Case No. 8284-VCN in the Court of Chancery of the State of Delaware, which is referred to as the Delaware Action, which reflects the consolidation of three actions originally filed in the Court of Chancery. The Texas State Action, the Texas Federal Action and the Delaware Action are collectively referred to as the “Actions.”

The Actions name Copano, R. Bruce Northcutt, William L. Thacker, James G. Crump, Ernie L. Danner, T. William Porter, Scott A. Griffiths, Michael L. Johnson, Michael G. MacDougall, Kinder Morgan GP, Kinder Morgan Energy Partners and Merger Sub as defendants. The Actions are purportedly brought on behalf of a putative class seeking to enjoin the merger and allege, among other things, that the members of Copano’s board of directors breached their fiduciary duties by agreeing to sell Copano for inadequate and unfair consideration and pursuant to an inadequate and unfair process, and that Copano, Kinder Morgan Energy Partners, Kinder Morgan GP and Merger Sub aided and abetted such alleged breaches. In addition, the plaintiffs in each of the Texas State Action and the Delaware Action allege that
the Copano directors breached their duty of candor to unitholders by failing to provide the unitholders with all material information regarding the merger and/or made misstatements in the preliminary proxy statement. The plaintiffs in the Texas Federal Action also assert a claim under the federal securities laws alleging that the preliminary proxy statement omits and/or misrepresents material information in connection with the merger.

On April 21, 2013, the parties in all the Actions executed a Memorandum of Understanding by which, in exchange for the full settlement and dismissal with prejudice of each of the Actions, Copano agreed to make certain additional disclosures concerning the merger in a Form 8-K filed by Copano on April 22, 2013. The parties are in the process of preparing and filing a Stipulation of Settlement and such other additional documents as may be required to in the Delaware Chancery Court for approval of the settlement.2014.

Other Commercial Matters
Union Pacific Railroad Company Easements
SFPP and UPRRUnion Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the judge determined that the annual rent payable as of January 1, 2004 was $15$14 million,, subject to annual consumer price index increases. Judgment was entered by the Court on May 29, 2012 and SFPP intends to appealappealed the judge’s determination, but if that determinationjudgment. If the judgment is upheld on appeal, SFPP would owe approximately $75$93 million in back rent. Accordingly, during 2011, we have increased our rights-of-way liability to cover this potential liability amount.for back rent. In addition, the judge determined that UPRR is entitled to an estimated $20approximately $20 million for interest through the date of the judgment on the outstanding back rent liability. We believe the award of interest is without merit and we are pursuing our appellate rights. By notice dated October 25, 2013, UPRR demanded the payment of $22.25 million in rent for the first year of the next ten-year period beginning January 1, 2014. SFPP rejected the demand and the parties are pursuing the dispute resolution procedure in their contract to determine the rental adjustment, if any, for such period.

26


SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In July 2006, a

27


trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision. In addition, UPRR contends that SFPP must comply with the more expensive AREMAAmerican Railway Engineering and Maintenance-of-Way Association (AREMA) standards in determining when relocations are necessary and in completing relocations. Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. A trial occurred in the fourth quarter of 2011, with a verdict having been reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. On March 10, 2014, the trial court issued a tentative statement of decision addressing all of the causes of action and defenses and resolved those matters against SFPP, consistent with the jury’s verdict. If the tentative statement of decision and jury verdict become final and are affirmed on appeal, SFPP will be required to pay a judgment of at least $22.6 million.UPRR has also requested the trial court award prejudgment interest and costs to UPRR. SFPP is evaluatingcontinuing to evaluate its post-trial and appellate options.
Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position, our results of operations, our cash flows, and our distributions to our limited partners. These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.
Severstal Sparrows Point Crane Collapse
On June 4, 2008, a bridge crane owned by Severstal and located in Sparrows Point, Maryland collapsed while being operated by KMBT.our subsidiary Kinder Morgan Bulk Terminals, Inc. (KMBT). According to our investigation, the collapse was caused by unexpected, sudden and extreme winds. On June 24, 2009, Severstal filed suit against KMBT in the United StatesU.S. District Court for the District of Maryland, Case No. 09CV1668-WMN. Severstal and its successor in interest, RG Steel, allege that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse. RG Steel seeks to recover in excess of $30$30 million for the alleged value of the crane and lost profits. KMBT denies each of RG Steel’s allegations. A bench trial occurred in November 2013. On or about June 1, 2012, RG Steel filed for bankruptcy in Case No. 12-11669March 6, 2014, the Court issued findings of fact and conclusions of law and entered judgment against KMBT in the United States Bankruptcyamount of $13.79 million. KMBT has filed a notice of appeal of the judgment.
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al
On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arises from the Districtsale by TGP of Delaware; consequently, the trial dateCameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleges damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica has been postponed indefinitely.agreed to indemnify TGP in connection with the gas commitment and reporting claims. The suit was removed to federal court and Plains has filed a motion to remand. We intend to vigorously defend the suit.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

27


General
As of March 31, 20132014 and December 31, 2012, we have recorded a2013, our total reserve for legal fees, transportation rate casesmatters was $655 million and other potential litigation liabilities in the amount of $431$611 million, and $404 million, respectively. The reserve is primarily relatedrelates to various claims from regulatory proceedings arising from our products pipeline and natural gas pipeline transportation rates. We regularly assess
Other
Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc., et al
On February 5, 2014, a putative class action and derivative complaint was filed in the likelihoodCourt of potential adverse outcomesChancery in pending mattersthe State of Delaware (Case No. 9318) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Jon Slotoroff, a purported unitholder of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit alleges direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleges that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit seeks disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. On March 3, 2014, nominal defendant KMEP and defendants KMI and KMGP moved to dismiss this suit. Defendants believe that this suit is without merit and intend to defend it vigorously.
Burns et al v. Kinder Morgan, Inc. Kinder Morgan G.P., Inc. et al
On March 27, 2014, a putative class action and derivative complaint was filed in the Court of Chancery in the State of Delaware (Case No. 9479) against defendants KMI, KMGP and nominal defendant KMEP. The suit was filed by Darrell Burns and Terrence Zehrer, purported unitholders of KMEP, and seeks to assert claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the suit. The suit asserts claims and allegations substantially similar to the suit filed by Jon Slotoroff described above. On April 8, 2014, the Court ordered that this suit be consolidated for all purposes with the suit filed by Jon Slotoroff described above and that the caption of the consolidated action shall be In Re Kinder Morgan Energy Partners, L.P. Derivative Litigation, Consolidated Case No. 9318.
Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al
On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist and Perry M. Waughtal. The suit was filed by Kenneth Walker, a purported unit holder of KMP, and alleges direct and derivative causes of action for alleged violation of duties owed under the partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit seeks unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demands a trial by jury. Defendants believe that this suit is without merit and intend to defend it vigorously. On April 9, 2014, the Court entered an order staying the case until the defendants’ motion to determinedismiss is decided in the adequacy of our reserves.suit filed by Jon Slotoroff described above.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time to time. In particular, the Comprehensive Environmental Response, Compensation and Liability Act, also know as CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are

28


inherent in pipeline, terminal and carbon dioxideCO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws,

28


regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. Specifically, we are involved in matters including incidents at terminal facilities in New Jersey and Texas involving PHMSA and the Texas Commission on Environmental Quality, respectively, which may result in fines and penalties for alleged violations. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or distributions to limited partners.
We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids,NGL, natural gas and carbon dioxide.
Colorado Oil and Gas Conservation Commission Inspections
In Fall 2012, the Colorado Oil and Gas Conservation Commission (COGCC) performed inspections at multiple well sites in Southwestern Colorado owned by Kinder Morgan CO2Company, L.P. and some of these inspections resulted in alleged violations of COGCC’s rules. Kinder Morgan took immediate steps to correct the alleged deficiencies and has engaged COGCC and other agencies in its efforts to maintain compliance. In April 2013, COGCC proposed a penalty of .$300,000 to resolve the matter. We are evaluating the proposed penalty as well as potential responses to the alleged violations.

New Jersey Department of Environmental Protection v. Occidental Chemical Corporation, et al. (Defendants), Maxus Energy Corp. and Tierra Solutions, Inc. (Third Party Plaintiffs) v. 3M Company et al., Superior Court of New Jersey, Law Division - Essex County, Docket No. L-9868-05
The NJDEPNew Jersey Department of Environmental Protection (NJDEP) sued Occidental Chemical Corporation (Occidental) and others under the New Jersey Spill Act for contamination in the Newark Bay Complex including numerous waterways and rivers. In 2009, Occidental et al. then brought inasserted claims for contribution against approximately 300 third party defendants for contribution.defendants. NJDEP claimed damages related to forty40 years of discharges of TCDD (a form of dioxin), DDT and “other hazardous substances.” GATX Terminals Corporation (n/k/a/ KMLT)a Kinder Morgan Liquids Terminals LLC) (KMLT) was brought innamed as a third party defendant because of the noted hazardous substances language and because the Carteret, New Jersey facility (a former GATX Terminals Corporation facility) is located on the Arthur Kill River, one of the waterways included in the litigation. This case was filed against third party defendants in 2009. Recently, KMLT, as part of a joint defense group, entered a settlement agreement (Consent(the Consent Judgment) with the NJDEP whereby the settling parties for a prescribed payment getobtained a contribution bar against first party defendants Occidental, Maxus Energy Corp. (Maxus) and Tierra Solutions, Inc. (Tierra) in addition to a release. This third-partyrelease of claims. The Consent Judgment will bewas published in the New Jersey Register followed byfor a 60-day comment period after which it will be lodged with the court.and no significant comments were received. Additionally, we have information that the NJDEP has reached an agreement in principle on terms for a settlement agreement with Maxus and Tierra. Occidental is not part of the settlement. As part of thisOn December 12, 2013, the Court approved the settlements. Pursuant to the Consent Judgment, KMLT submitted its settlement these defendants agree to dismiss all direct claims against third-party defendantspayment by the January 27, 2014 deadline and to not opposereceived the third-party settlement. We expectCourt’s order dismissing KMLT from the first-party settlement to be finalized over the next 60 days. All discovery and trial proceedings are stayed during these settlement negotiations.litigation.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the U.S. Environmental Protection Agency (U.S. EPA) sent outEPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-

29


votingnon-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the Remedial Investigationremedial investigation and Feasibility Studyfeasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. Once the U.S. EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision. Currently, KMLT and 90 other parties are involved in an allocation process to determine each party’s respective share of the cleanup costs. This is a non-judicial allocation process. We are participating in the allocation process on behalf of both KMLT and KMBT. Each entity has two facilities located in Portland Harbor. We expect the allocation process to conclude in 2013 or 2014, depending upon when2015. We also expect the U.S.LWG to complete the RI/FS process in 2015, after which the EPA issues itsis expected to develop a proposed plan leading to a Record of Decision targeted for 2017. It is anticipated that the cleanup activities will begin within one year of the issuance of the Record of Decision.

29


Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
This is a CERCLA case brought against a number of defendants by a water purveyor whose wells have allegedly been contaminated due to the presence of a number of contaminants. The Roosevelt Irrigation District issued KMGP, KMEP and others under CERCLA for contamination of the water purveyor’s wells.  The First Amended Complaint sought $175 million in damages against approximately 70 defendants.  On August 6, 2013, plaintiffs filed its Second Amended Complaint seeking upmonetary damages in unspecified amounts and reducing the number of defendants to $175 million26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from approximately 70 defendants. The plume of contaminants has traveled under Kinder Morgan’s Phoenix Terminal. The plaintiffs have advanced a novel theory thatspecific parcel within the releases of petroleum from theSFPP Phoenix Terminal (which are exempt underand the petroleum exclusion under CERCLA) have facilitatedalleged impact of such releases on water wells owned by the natural degradationplaintiffs and located in the vicinity of certain hazardous substances and thereby have resulted in a release of hazardous substances regulated under CERCLA. We are part of a joint defense group consisting of other terminal operators at the Phoenix Terminal including Chevron, BP, Salt River Project, Shell and a number of others, collectively referred to as the terminal defendants. Together,Terminal. On October 24, 2013, we filed a motionmoved to dismiss all claims based on the petroleum exclusion under CERCLA. This case was assigned to a new judge, who has deemed all previous motions withdrawn and will grant leave to re-file such motions at a later date. We plan to re-file the motion to dismiss as well as numerous summary judgment motions as the judge allows.this suit.

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

KMLT iswas a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles. The lawsuit was stayed beginning in 2009 and remained stayed following the last case management conference in March 2013. During the stay, the parties deemed responsible by the local regulatory agency (including the City of Los Angeles) have worked with that agency concerning the scope of the required cleanup. We anticipate that cleanup activities by the Port at the site will begin in the summer of 2013. On April 9, 2013, KMLT and the Port of Los Angeles entered into a Settlement and Release Agreementsettlement agreement, the terms of which provide for the dismissal of the litigation by the Port upon the payment by KMLT of and KMLT’s agreement to pay 60% of the Port’s costs to remediate the former terminal site; the amount of payment notsite up to exceed $15a $15 million. The parties also filed a Good Faith Settlement motion in the Superior Court as part of the process of dismissal of the case. cap. Further, according to terms of the Settlement and Release,settlement agreement, we received a 5-yearfive-year lease extension that allows KMLT to continue fuel loading and offloading operations at another KMLT Port of Los Angeles terminal property. The Court approved the parties’ Good Faith Settlement motion and dismissed the case.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC
The City of Los Angeles, KMLT, Chevron and ST Services, Inc.
On April 23, 2003, ExxonMobil filedPhillips 66 remain named on a complaintCleanup and Abatement Order from the California Regional Water Quality Control Board as parties responsible for the cleanup of the former Los Angeles Marine Terminal. The private parties have all settled with the City of Los Angeles and agreed to pay a percentage of the City’s costs to perform the required cleanup at the site. Cleanup activities by the Port began in the Superior Courtfirst quarter of New Jersey, Gloucester County. The lawsuit relates to environmental remediation obligations at a 2014.

Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The terminal is now owned by Plains Products, and it too is a party to the lawsuit.Liquids Terminal Consent Judgment

On June 25, 2007, the NJDEP, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint in Gloucester County, New Jersey against ExxonMobil and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro, terminal.New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corporation from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC. The complaintterminal is now owned by Plains Products, which was filed in Gloucester County, New Jersey.  Both ExxonMobil and KMLT filed thirdalso joined as a party complaints against Support Terminals/Plains and successfully brought Support Terminals/Plains intoto the case. The court consolidated the two cases.lawsuit. 

In mid 2011,mid-2011, KMLT and Plains Products entered into a settlement agreement and subsequent Consent Judgment with the NJDEP for settlement ofwhich resolved the state’s alleged natural resource damages claim. The parties then entered into a Consent Judgment concerning the claim.

30


The natural resource damage settlement includes a monetary award of $1$1 million and a series of remediation and restoration activities at the terminal site. KMLT and Plains Products have joint responsibility for this settlement. Simultaneously, KMLT and Plains Products entered into a settlementan agreement that settled each party’s relative share of responsibility (50/50) to the NJDEP under the Consent Judgment noted above. The Consent Judgment is now entered with the Court and the settlement is final. According to the agreement, Plains will conduct remediation activities at the site and KMLT will provide oversight and 50% of the costs. We are awaiting approval from the NJDEP in order to begin remediation activities.

The settlement with the state did not resolve the original complaint brought by ExxonMobil. On or around, April 10, 2013, KMLT, Plains and ExxonMobil settled the original Exxon complaint for past remediation costs for $750,000 to be split 50/50 between KMLT and Plains. All parties have now executed the agreement and the litigation is settled and dismissed.
Mission Valley Terminal Lawsuit

In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL. On September 26, 2007, we removed the case to the United StatesU.S. District Court, Southern District of California, case number 07CV1883WCAB. The City disclosed in discovery that it is seeking approximately $170$170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later,

30


in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.$365 million.
In accordance with the Case Management Order, the parties filed their respective summary adjudication motions and motions to exclude experts on June 29, 2012. 
On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ pendingsummary adjudication motions.  The Court tentatively granted our motions to exclude certain of the City’s proposed expert witnesses, tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims.  On January 25, 2013, the Court issued its final order reaffirming in all respects its tentative rulings and rendered judgment in favor of all defendants on all claims asserted by the City. 

On February 20, 2013, the City of San Diego filed a notice of appeal of this case to the U.S. Court of Appeals for the Ninth Circuit. The appeal is currently pending.

This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board.Board (RWQCB).  SFPP continues to conduct an extensive remediation effort at the City’s stadium property site.

On May 7, 2013, the City of San Diego filed a writ of mandamus to the California Superior Court seeking an order from the Court setting aside the RWQCB’s approval of our permit request to increase the discharge of water from our groundwater treatment system to the City of San Diego’s municipal storm sewer system. KMEP is coordinating with the RWQCB to oppose the City’s writ.

Uranium Mines in Vicinity of Cameron, Arizona

In the 1950s and 1960s, Rare Metals Inc., an historical subsidiary of EPNG, operated approximately twenty20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation.  The mining activities were in response to numerous incentives provided to industry by the United StatesU.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program.  In May 2012, EPNG received a general notice letter from the U.S. EPA notifying EPNG of the EPA'sEPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA.  In FebruaryAugust 2013, EPNG and the EPA delivered a proposedentered into an Administrative Order on Consent and proposed Scope of Work, regardingpursuant to which EPNG will conduct a radiological assessment of the government's proposed next steps to investigatesurface of the mines.  We are negotiating the terms and conditions of both the Administrative Order on Consent and the Scope of Work.  We are also seeking contribution from the United Statesapplicable federal government agencies toward the cost of environmental activities associated with the mines, given itstheir pervasive control over all aspects of the nuclear weapons program.

PHMSA Inspection of Carteret Terminal, Carteret, New Jersey

On April 4, 2013, the PHMSA, Office of Pipeline Safety issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (NOPV) arising from an inspection at the KMLT, Carteret, New Jersey location on March 15, 2011, following a release and fire that occurred during maintenance activity on March 14, 2011. On July 17, 2013, KMLT entered into a Consent Agreement and Order with the PHMSA, pursuant to which KMLT paid a penalty of $63,100 and is required to complete ongoing pipeline integrity testing and other corrective measures by May 2015.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP and approximately 100 energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The Flood Protection Authority asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On September 10, 2013, the Flood Protection Authority filed a motion to remand the case to the state district court for Orleans Parish. On December 18, 2013, a hearing was conducted on the remand motion and it remains under consideration by the court.

31



Plaquemines Parish Louisiana Coastal Zone Litigation
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. On December 18, 2013, defendants removed the case to the U.S. District Court for the Eastern District of Louisiana. On January 14, 2014, the plaintiff filed a motion to remand the case to state court and such motion remains pending.
Pennsylvania Department of Environmental Protection Notice of Alleged Violations
The Pennsylvania Department of Environmental Protection (PADEP) has notified TGP of alleged violations of certain conditions to the construction permits issued to TGP for the construction of TGP’s 300 Line Project in 2011. The alleged violations arise from field inspections performed during construction by county conservation districts, as delegates of the PADEP, and generally involve the alleged failure by TGP to implement and maintain best practices to achieve sufficient erosion and sediment controls, stabilization of the right of way, and prevention of potential discharge of sediment into the waters of the commonwealth during construction and before placing the line into service. To resolve such alleged violations, the PADEP initially proposed a collective penalty of approximately $1.5 million. TGP and the PADEP are seeking to reach a mutually agreeable resolution of the alleged notices of violations, including an agreed penalty amount.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, we are not able to reasonably estimate when the eventual resolution of such claims will occur, and changing circumstances could cause these matters to have a material

31


adverse impact. As of March 31, 20132014 and December 31, 2012, we have accrued a2013, our total reserve for environmental liabilities in the amount of $163was $164 million and $166$168 million,, respectively. Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.
10. Regulatory Matters and Accounting for Regulatory Activities
Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process.  We included the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Accrued other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets. The recovery period for these regulatory assets is approximately 20 years.

The following table summarizes our regulatory asset and liability balances (in millions):

 March 31, 2013 December 31, 2012
Current regulatory assets$26
 $18
Non-current regulatory assets203
 204
Total Regulatory Assets$229
 $222
    
Current regulatory liabilities$4
 $4
Non-current regulatory liabilities62
 65
Total Regulatory Liabilities$66
 $69

More information about our regulatory matters can be found in Note 17 Regulatory Matters” to our consolidated financial statements that were included in our 2012 Form 10-K.

11. Recent Accounting Pronouncements
Accounting Standards Updates
None of the Accounting Standards Updates (ASU) that we adopted and that became effective January 1, 20132014 (including (i) ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets and Liabilities;” (ii) ASU No. 2012-02, “Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment;” (iii) ASU No. 2013-01, “Clarifyingwithin a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the Scope of Disclosures about Offsetting Assets and Liabilities;” and (iv) ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”FASB Emerging Issues Task Force)) had a material impact on our consolidated financial statements. More information about the four ASUs listed abovethis ASU can be found in Note 1817 Recent Accounting Pronouncements” to our consolidated financial statements that were included in our 20122013 Form 10-K.
11. Guarantee of Securities of Subsidiaries

KMEP has guaranteed the payment of Copano’s outstanding 7.125% senior notes due April 1, 2021 (referred to in this report as the “Guaranteed Notes”). Copano Energy Finance Corporation (Copano Finance Corp.), a direct subsidiary of Copano, is the co-issuer of the Guaranteed Notes. Excluding fair value adjustments, as of March 31, 2014, Copano had $332 million of Guaranteed Notes outstanding. Copano Finance Corp’s obligations as a co-issuer and primary obligor are the same as and joint and several with the obligations of Copano as issuer, however, it has no subsidiaries and no independent assets or operations. Subject to the limitations set forth in the applicable supplemental indentures, KMEP’s guarantee is full and unconditional and guarantees the Guaranteed Notes through their maturity date.

32


A significant amount of KMEP’s income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. For purposes of the condensed consolidating financial information, distributions from our wholly owned subsidiaries have been presented as operating cash flows whether or not distributions exceeded cumulative earnings. In addition, we utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the subsidiary issuers and non-guarantor subsidiaries. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.

Included among the non-guarantor subsidiaries are KMEP’s five operating limited partnerships and their majority-owned and controlled subsidiaries, along with Copano’s remaining majority-owned and controlled subsidiaries. In the following unaudited condensed consolidating financial information, KMEP is “Parent Guarantor,” and Copano and Copano Finance Corp. are the “Subsidiary Issuers.” The Subsidiary Issuers are 100% owned by KMEP.

Condensed Consolidating Statement of Income for the Three Months ended March 31, 2014
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Revenues$
 $
 $3,652
 $
 $3,652
Operating Costs, Expenses and Other         
Costs of sales
 
 1,638
 
 1,638
Depreciation, depletion and amortization
 
 401
 
 401
Other operating expenses
 7
 673
 
 680
Total Operating Costs, Expenses and Other
 7
 2,712
 
 2,719
Operating (Loss) Income
 (7) 940
 
 933
Other Income (Expense), Net749
 33
 (163) (782) (163)
Income from Continuing Operations Before Income Taxes749
 26
 777
 (782) 770
Income Tax Expense(3) 
 (13) 
 (16)
Net Income746
 26
 764
 (782) 754
Net Income Attributable to Noncontrolling Interests
 
 (8) 
 (8)
Net Income Attributable to KMEP$746
 $26
 $756
 $(782) $746
Condensed Consolidating Statement of Income for the Three Months ended March 31, 2013
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Revenues$
 $
 $2,661
 $
 $2,661
Operating Costs, Expenses and Other         
Costs of sales
 
 957
 
 957
Depreciation, depletion and amortization
 
 328
 
 328
Other operating expenses
 
 592
 
 592
Total Operating Costs, Expenses and Other
 
 1,877
 
 1,877
Operating Income
 
 784
 
 784
Other Income, Net786
 
 101
 (776) 111
Income from Continuing Operations Before Income Taxes786
 
 885
 (776) 895
Income Tax Expense(3) 
 (98) 
 (101)
Income from Continuing Operations783
 
 787
 (776) 794
Loss from Discontinued Operations
 
 (2) 
 (2)
Net Income783
 
 785
 (776) 792
Net Income Attributable to Noncontrolling Interests
 
 (9) 
 (9)
Net Income Attributable to KMEP$783
 $
 $776
 $(776) $783

33



Condensed Consolidating Statement of Comprehensive Income
for the Three Months ended March 31, 2014
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Net Income$746
 $26
 $764
 $(782) $754
Other Comprehensive Income (Loss):         
Change in fair value of derivatives utilized for hedging purposes(56) 
 (56) 56
 (56)
Reclassification of change in fair value of derivatives to net income18
 
 18
 (18) 18
Foreign currency translation adjustments(78) 
 (79) 78
 (79)
Adjustments to pension and other postretirement benefit plan liabilities(2) 
 (2) 2
 (2)
Total Other Comprehensive Loss(118) 
 (119) 118
 (119)
Comprehensive Income628
 26
 645
 (664) 635
Comprehensive Income Attributable to Noncontrolling Interests
 
 (7) 
 (7)
Comprehensive Income Attributable to KMEP$628
 $26
 $638
 $(664) $628
Condensed Consolidating Statement of Comprehensive Income
for the Three Months ended March 31, 2013
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Net Income$783
 $
 $785
 $(776) $792
Other Comprehensive Income (Loss):         
Change in fair value of derivatives utilized for hedging purposes(40) 
 (41) 40
 (41)
Reclassification of change in fair value of derivatives to net income(7) 
 (7) 7
 (7)
Foreign currency translation adjustments(43) 
 (43) 43
 (43)
Adjustments to pension and other postretirement benefit plan liabilities1
 
 1
 (1) 1
Total Other Comprehensive Loss(89) 
 (90) 89
 (90)
Comprehensive Income694
 
 695
 (687) 702
Comprehensive Income Attributable to Noncontrolling Interests
 
 (8) 
 (8)
Comprehensive Income Attributable to KMEP$694
 $
 $687
 $(687) $694


34


Condensed Consolidating Balance Sheet as of March 31, 2014
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
ASSETS         
Cash and cash equivalents$22
 $
 $325
 $
 $347
All other current assets3,224
 5
 2,168
 (3,061) 2,336
Property, plant and equipment, net
 191
 28,367
 
 28,558
Investments
 
 2,263
 
 2,263
Investments in subsidiaries13,930
 4,348
 
 (18,278) 
Goodwill
 813
 5,793
 
 6,606
Notes receivable from affiliates18,199
 
 
 (18,199) 
Other non-current assets251
 
 3,597
 
 3,848
Total Assets$35,626
 $5,357
 $42,513
 $(39,538) $43,958
          
LIABILITIES AND PARTNERS’ CAPITAL         
Liabilities         
Current portion of debt$1,243
 $
 $
 $
 $1,243
All other current liabilities173
 88
 5,756
 (3,061) 2,956
Total long-term debt16,882
 391
 3,572
 
 20,845
Notes payable to affiliates
 832
 17,367
 (18,199) 
Deferred income taxes
 2
 275
 
 277
Other long-term liabilities and deferred credits152
 
 862
 
 1,014
     Total Liabilities18,450
 1,313
 27,832
 (21,260) 26,335
          
Partners’ Capital         
Total KMEP Partners’ Capital17,176
 4,044
 14,234
 (18,278) 17,176
Noncontrolling interests
 
 447
 
 447
     Total Partners’ Capital17,176
 4,044
 14,681
 (18,278) 17,623
Total Liabilities and Partners’ Capital$35,626
 $5,357
 $42,513
 $(39,538) $43,958

35


Condensed Consolidating Balance Sheet as of December 31, 2013
(In Millions)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
ASSETS         
Cash and cash equivalents$10
 $1
 $393
 $
 $404
All other current assets3,071
 13
 2,151
 (2,971) 2,264
Property, plant and equipment, net
 170
 27,235
 
 27,405
Investments
 
 2,233
 
 2,233
Investments in subsidiaries13,931
 4,430
 
 (18,361) 
Goodwill
 813
 5,734
 
 6,547
Notes receivable from affiliates17,284
 
 
 (17,284) 
Other non-current assets233
 
 3,678
 
 3,911
Total Assets$34,529
 $5,427
 $41,424
 $(38,616) $42,764
          
LIABILITIES AND PARTNERS’ CAPITAL         
Liabilities         
Current portion of debt$1,504
 $
 $
 $
 $1,504
All other current liabilities407
 107
 5,530
 (2,971) 3,073
Total long-term debt15,644
 393
 3,587
 
 19,624
Notes payable to affiliates
 907
 16,377
 (17,284) 
Deferred income taxes
 2
 283
 
 285
Other long-term liabilities and deferred credits173
 
 884
 
 1,057
     Total Liabilities17,728
 1,409
 26,661
 (20,255) 25,543
          
Partners’ Capital         
Total KMEP Partners’ Capital16,801
 4,018
 14,343
 (18,361) 16,801
Noncontrolling interests
 
 420
 
 420
     Total Partners’ Capital16,801
 4,018
 14,763
 (18,361) 17,221
Total Liabilities and Partners’ Capital$34,529
 $5,427
 $41,424
 $(38,616) $42,764


36


Condensed Consolidating Statement of Cash Flow for the Three Months ended March 31, 2014
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Net Cash Provided by (Used in) Operating Activities$687
 $(3) $1,444
 $(1,054) $1,074
          
Cash Flows From Investing Activities         
Business acquisitions (Note 2)
 
 (960) 
 (960)
Acquisitions of assets-other
 
 (25) 
 (25)
Loans to related party(17) 
 
 
 (17)
Capital expenditures
 (27) (782) 
 (809)
Contributions to investments
 
 (35) 
 (35)
Distributions from equity investments in excess of cumulative earnings
 
 15
 
 15
Funding (to) from affiliates(545) 97
 740
 (292) 
Natural gas storage and natural gas and liquids line-fill
 
 21
 
 21
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs
 
 19
 
 19
Other, net(5) 
 (5) 
 (10)
Net Cash (Used in) Provided by Investing Activities(567) 70
 (1,012) (292) (1,801)
          
Cash Flows From Financing Activities         
Issuance of debt4,498
 
 
 
 4,498
Payment of debt(3,568) 
 (1) 
 (3,569)
Debt issue costs(10) 
 
 
 (10)
Funding (to) from affiliates(769) (68) 545
 292
 
Proceeds from issuance of common units619
 
 
 
 619
Proceeds from issuance of i-units6
 
 
 
 6
Contributions from noncontrolling interests
 
 32
 
 32
Distributions to partners and noncontrolling interests(883) 
 (1,066) 1,054
 (895)
Other, net(1) 
 
 
 (1)
Net Cash Used in Financing Activities(108) (68) (490) 1,346
 680
          
Effect of Exchange Rate Changes on Cash and Cash Equivalents
 
 (10) 
 (10)
          
Net increase (decrease) in Cash and Cash Equivalents12
 (1) (68) 
 (57)
Cash and Cash Equivalents, beginning of period10
 1
 393
 
 404
Cash and Cash Equivalents, end of period$22
 $
 $325
 $
 $347

37


Condensed Consolidating Statement of Cash Flow for the Three Months ended March 31, 2013
(In Millions)
(Unaudited)
 Parent Guarantor Subsidiary Issuers Non-guarantor Subsidiaries Eliminations Consolidated KMP
Net Cash Provided by Operating Activities$542
 $
 $1,074
 $(870) $746
          
Cash Flows From Investing Activities         
Payment to KMI for March 2013 drop-down asset group (Note 1)
 
 (988) 
 (988)
Acquisitions of assets-other
 
 (4) 
 (4)
Capital expenditures
 
 (552) 
 (552)
Proceeds from sale of investments in Express pipeline system
 
 403
 
 403
Contributions to investments
 
 (40) 
 (40)
Distributions from equity investments in excess of cumulative earnings
 
 19
 
 19
Funding to affiliates(1,614) 
 (411) 2,025
 
Natural gas storage and natural gas and liquids line-fill
 
 10
 
 10
Sale or casualty of property, plant and equipment, investments and other net assets, net of removal costs
 
 (3) 
 (3)
Other, net(17) 
 1
 
 (16)
Net Cash Used in Investing Activities(1,631) 
 (1,565) 2,025
 (1,171)
          
Cash Flows From Financing Activities         
Issuance of debt2,685
 
 14
 
 2,699
Payment of debt(1,715) 
 (94) 
 (1,809)
Debt issue costs(7) 
 
 
 (7)
Funding from affiliates411
 
 1,614
 (2,025) 
Proceeds from issuance of common units385
 
 
 
 385
Contributions from noncontrolling interests
 
 65
 
 65
Pre-acquisition contributions from KMI to March 2013 drop-down asset group
 
 35
 
 35
Distributions to partners and noncontrolling interests(721) 
 (879) 870
 (730)
Net Cash Provided by Financing Activities1,038
 
 755
 (1,155) 638
          
Effect of Exchange Rate Changes on Cash and Cash Equivalents
 
 (6) 
 (6)
          
Net (decrease) increase in Cash and Cash Equivalents(51) 
 258
 
 207
Cash and Cash Equivalents, beginning of period95
 
 434
 
 529
Cash and Cash Equivalents, end of period$44
 $
 $692
 $
 $736

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

General and Basis of Presentation
The following discussion and analysis should be read in conjunction with (i) our accompanying interim consolidated financial statements and related notes (included elsewhere in this report); (ii) our consolidated financial statements and related notes included in our 20122013 Form 10-K; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 20122013 Form 10-K.

32


We prepared our consolidated financial statements in accordance with U.S. generally accepted accounting principles.GAAP. In addition, as discussed in Note 1 General” and Note 2 Acquisitions and Discontinued Operations”Divestitures” to our consolidated financial statements, included elsewhere in this report, our financial statements reflect:
reflect our March 1, 2013 acquisition of net assets from KMIdrop-down transaction as if such acquisition had taken place on the effective dates of common control pursuant to generally accepted accounting principles. We refer to this transfer of net assets from KMI to us as the drop-down transaction, and we refer to the transferred assets as our drop-down asset group.control. We accounted for the March 2013 drop-down transaction as a combination of entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition

38


and Results of Operations includeincludes the financial results of the March 2013 drop-down asset group for all periods subsequent to the effective dates of common control; andcontrol.
the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. We sold our FTC Natural Gas Pipelines disposal group to Tallgrass Development, LP (now known as Tallgrass Energy Partners, LP) effective November 1, 2012 for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In the first quarter of 2013, following final working capital and other liability account reconciliations, we recorded an incremental loss of $2 million related to our sale of the disposal group, and except for this loss amount, we recorded no other financial results from the operations of the disposal group during the first quarter of 2013. Furthermore, we have excluded the disposal group’s financial results from our Natural Gas Pipelines business segment disclosures for the three months ended March 31, 2012.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of U.S. generally accepted accounting principlesGAAP involves the exercise of varying degrees of judgment.  Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared.  These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.  We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances.  Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Furthermore, with regard to goodwill impairment testing, we review our goodwill for impairment annually, and we evaluated our goodwill for impairment on May 31, 2012.2013. Our goodwill impairment analysis performed onas of that date did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets.
Further information about us and information regarding our accounting policies and estimates that we consider to be “critical” can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” ofin our 20122013 Form 10-K.


33


Results of Operations
In our discussionsNon-GAAP Measures

The non-GAAP financial measures of (i) DCF before certain items, both in the operating resultsaggregate and per unit, and (ii) segment earnings before DD&A; amortization of individual businesses that follow, we generally identify the important fluctuations between periodsexcess cost of equity investments; and certain items, are presented belowunder “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are attributablerequired by GAAP to acquisitionsbe reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and dispositions separately from thosein our view are likely to occur only sporadically.

Our non-GAAP measures described below should not be considered as an alternative to GAAP net income, operating income or any other GAAP measure. DCF before certain items, and segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income, and because DCF measures are attributabledefined differently by different companies in our industry, our DCF before certain items may not be comparable to businesses ownedDCF measures of other companies. Segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, has similar limitations. Our management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in both periods.its analysis and its decision making processes.
Consolidated
Results of Operations
 Three Months Ended
March 31,
  
 2013
2012 
Earnings
increase/(decrease)
 (In millions, except percentages)
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments(a)       
Natural Gas Pipelines$557
 $222
 $335
 151 %
CO2
342
 334
 8
 2 %
Products Pipelines185
 176
 9
 5 %
Terminals186
 187
 (1) (1)%
Kinder Morgan Canada193
 50
 143
 286 %
Segment earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments (EBDA)(b)1,463
 969
 494
 51 %
Depreciation, depletion and amortization expense(c)(328) (239) (89) (37)%
Amortization of excess cost of equity investments(2) (2) 
  %
General and administrative expense(d)(134) (107) (27) (25)%
Interest expense, net of unallocable interest income(e)(202) (139) (63) (45)%
Unallocable income tax expense(3) (2) (1) (50)%
Income from continuing operations794
 480
 314
 65 %
Loss from discontinued operations(f)(2) (272) 270
 99 %
Net Income792
 208
 584
 281 %
Net Income attributable to noncontrolling interests(g)(9) (2) (7) (350)%
Net Income attributable to Kinder Morgan Energy Partners, L.P.$783

$206
 $577
 280 %
____________
(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)
2013 and 2012 amounts include an increase in earnings of $187 million and a decrease in earnings of $3 million, respectively, related to the combined effect from all of the 2013 and 2012 certain items impacting continuing operations and disclosed below in our management, discussion and analysis of segment results.
(c)
2013 amount includes a $19 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of March 1, 2013.
(d)
2013 and 2012 amounts include increases in expense of $14 million and $1 million, respectively, related to the combined effect from the 2013 and 2012 certain items related to general and administrative expenses disclosed below in “—Other.
(e)
2013 amount includes a $15 million increase in expense attributable to our drop-down asset group for periods prior to our acquisition date of March 1, 2013.
(f)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.2013 amount represents an incremental loss related to the sale of our disposal group effective November 1, 2012. 2012 amount includes a $322 million loss from a remeasurement of net assets to fair value, and $7 million of depreciation and amortization expense. The remaining 2012 amount ($57 million) represents our FTC Natural Gas Pipelines disposal group’s earnings before depreciation, depletion and amortization expenses.

34


(g)
2013 and 2012 amounts includean increase of $2 million and a decrease of $4 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2013 and 2012 certain items disclosed below in both our management discussion and analysis of segment results and “—Other.

Distributable Cash Flow

As more fully described in our 20122013 Form 10-K, we own and manage a diversified portfolio of energy transportation, production and storage assets, and primarily, our business model is designed to generate stable, fee-based income that provides overall long-term value to our unitholders. Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement

39


generally consists of all our cash receipts, less cash disbursements and changes in reserves). DistributableFor more information about our available cash flow, sometimes referredand partnership distributions, see Note 11 “Related Party Transactions—Partnership Interests and Distributions” to as our consolidated financial statements included in our 2013 Form 10-K.

DCF is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of available cash. We believe the primary measure of company performance used by us, investors and industry analysts covering MLPs is cash generation performance. Therefore, we believe DCF is an important measure to evaluate the operating and financial performance of the partnership and to compare it with the performance of other publicly traded MLPs within the industry. The following table discloses the calculation of our DCF for each of the three month periodsmonths ended March 31, 20132014 and 2012 is as follows2013 (calculated before the combined effect from all of the 2014 and 2013 certain items disclosed in the footnotes to the tables above)below):

Distributable Cash Flow
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
  
Net Income$792
 $208
$754
 $792
Add-back/(Less): Certain items - combined income (expense)(a)(137) 326
Add/(Less): Certain items - combined expense/(income)(a)34
 (137)
Net Income before certain items655
 534
788
 655
Less: Net Income before certain items attributable to noncontrolling interests(7) (6)(8) (7)
Net Income before certain items attributable to Kinder Morgan Energy Partners, L.P.648
 528
Net Income before certain items attributable to KMEP780
 648
Less: General Partner’s interest in Net Income before certain items(b)(401) (321)(453) (401)
Limited Partners’ interest in Net Income before certain items247
 207
327
 247
Depreciation, depletion and amortization(c)(e)338
 290
426
 338
Book (cash) taxes paid, net12
 9
17
 12
Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC1
 
(5) 1
Sustaining capital expenditures(d)(e)(48) (44)(72) (48)
Distributable cash flow (DCF) before certain items$550
 $462
Distributable cash flow before certain items$693
 $550
____________
(a)
Equal to the combined income (expense) effect from all of the 20132014 and 20122013 certain items disclosed in the footnotes to the “—Results of OperationsOperations” table included above.below (and described in more detail below in both our management’s discussion and analysis of segment results and “—Other”).
(b)
20132014 andamount includes both a 2012$30 million reduction for waived general partner incentive amounts include reductions of $4related to common units issued to finance our May 2013 Copano acquisition, and a $3 million and $6 million, respectively,reduction for waived general partner incentive amounts related to common units issued to finance a portion of theour January 2014 APT acquisition. 2013 amount includes a $4 million reduction for waived general partner incentive amounts related to common units issued to finance a portion of our July 2011 KinderHawk Field Services LLC acquisition.
(c)
20132014 and 20122013 amounts include expense amounts of$27 $22 million and $42$27 million, respectively, for our proportionate share of the depreciation, depletion and amortizationDD&A expenses of our unconsolidated joint ventures. 2013 amount also excludes a $19 million expense amount attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013. 2012 amount alsoincludes a $7 million expense attributable to our FTC Natural Gas Pipelines disposal group.acquisition.
(d)
20122014 amount includes expenditures of $2$1 million for our proportionate share of the sustaining capital expenditures of ourcertain unconsolidated joint ventures.
(e)
DCF includes our proportionate share of the depreciation, depletion and amortization expenses of our unconsolidated joint ventures, less our proportionate share of the sustaining expenditures of our unconsolidated joint ventures,In order to more closely track the cash distributions we receive from theseour unconsolidated joint ventures.ventures, our calculation of DCF (i) adds back our proportionate share of the DD&A expenses of certain joint ventures; and (ii) subtracts our proportionate share of the sustaining expenditures of the corresponding joint ventures (i.e. the same equity investees for which we add back DD&A as discussed in footnote (c)).

Consolidated Earnings Results

With regard to our reportable business segments, we consider each period’ssegment earnings before all non-cash depreciation, depletionDD&A expenses, and amortization expenses, including amortization of excess cost of equity investments, (definedto be an important measure of our success in maximizing returns to our partners. This measure, sometimes referred to in this report as segment EBDA, is more fully defined in footnote (a) to the —Results of Operations” table above and sometimes referred to in this report as EBDA) to be an important measure of our

35


success in maximizing returns to our partners.below. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be

For the comparable first quarter periods
40


considered in conjunction with net income and 2012, total segment EBDA increased $494 million (51%) in 2013; however, this overall increase:other performance measures such as operating income, income from continuing operations or operating cash flows.
Results of Operations
 Three Months Ended
March 31,
 
Earnings
increase/(decrease)
 2014 2013 
 (In millions, except percentages)
Segment EBDA(a)       
Natural Gas Pipelines$719
 $557
 $162
 29 %
CO2
363
 342
 21
 6 %
Products Pipelines208
 185
 23
 12 %
Terminals214
 186
 28
 15 %
Kinder Morgan Canada48
 193
 (145) (75)%
Segment EBDA(b)1,552
 1,463
 89
 6 %
DD&A expense(c)(401) (328) (73) (22)%
Amortization of excess cost of equity investments(3) (2) (1) (50)%
General and administrative expense(d)(153) (134) (19) (14)%
Interest expense, net of unallocable interest income(e)(239) (202) (37) (18)%
Unallocable income tax expense(2) (3) 1
 33 %
Income from continuing operations754
 794
 (40) (5)%
Loss from discontinued operations
 (2) 2
 100 %
Net Income754
 792
 (38) (5)%
Net Income attributable to noncontrolling interests(f)(8) (9) 1
 11 %
Net Income attributable to KMEP$746
 $783
 $(37) (5)%
____________
(a)Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other income, net. Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)
included2014 and 2013 amounts include a $190decrease in earnings of $17 million and an increase in EBDAearnings of $187 million, respectively, related to the combined effect from the effectall of the 2014 and 2013certain items referenced in footnote (b) to the —Results of Operations” table above (which combined to increase total segment EBDA fromimpacting continuing operations by $187 millionand disclosed below in the first quarterour management discussion and analysis of 2013 and decrease segment EBDA from continuing operations by $3 million in the first quarter of 2012); andresults.
(c)excluded
2013 amount includes a $57$19 million decreaseincrease in quarter-to-quarter EBDAexpense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
(d)
2014 and 2013 amounts include increases in expense of$6 million and $14 million, respectively, related to the combined effect from discontinued operations.all of the 2014 and 2013 certain items related to general and administrative expenses disclosed below in “—Other.”
(e)
2014 amount includes an $11 million increase in expense related to the combined effect from all of the 2014 certain items related to interest expense, net of unallocable interest income disclosed below in “—Other.” 2013 amount includes a $15 million increase in expense attributable to our March 2013 drop-down asset group for periods prior to our March 1, 2013 acquisition date.
(f)2014 amount includes a $2 million increase in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2014 certain items disclosed below in both our management’s discussion and analysis of segment results and “—Other.”

The certain items described in footnote (b) to the table above accounted for a$204 million decrease in EBDA in the first quarter of 2014, when compared to the same prior year period. After adjusting fortaking into effect these twocertain items, the remaining $247$293 million (24%(23%) quarter-to-quarter increase in quarterly segment earnings before depreciation, depletion and amortization resulted primarily fromEBDA was largely driven by better performance in the first quarter of 20132014 from our Natural Gas Pipelines, Terminals and Products Pipelines business segments. Combined EBDA from our CO2, Terminals and Kinder Morgan Canada business segments were relatively flat across both comparable three-month periods.segments.

41


Natural Gas Pipelines
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues(a)$1,369
 $794
$2,176
 $1,369
Operating expenses(b)(860) (608)(1,501) (860)
Other income4
 
Earnings from equity investments(c)48
 38
43
 48
Interest income and Other, net1
 

 1
Income tax expense(1) (2)(3) (1)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments from continuing operations557
 222
Discontinued operations(d)(2) (265)
Earnings (loss) before depreciation, depletion and amortization expense and amortization of excess cost of equity investments including discontinued operations$555
 $(43)
EBDA from continuing operations719
 557
Discontinued operations
 (2)
Certain items, net(a)(b)(c)4
 (58)
EBDA before certain items$723
 $497
      
Natural gas transport volumes (Bcf)(e)1,536.6
 1,436.4
Natural gas sales volumes (Bcf)(e)212.1
 212.8
Change from prior periodIncrease/(Decrease)
Revenues before certain items(a)$922
 67%
EBDA before certain items$226
 45%
   
Natural gas transport volumes (BBtu/d)(d)17,938.2
 17,073.4
Natural gas sales volumes (BBtu/d)(e)2,254.0
 2,357.0
Natural gas gathering volumes (BBtu/d)(f)2,871.3
 2,889.3
____________
(a)
2014 amount includes a decrease in revenues of $4 million related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. 2013 amount includes an increase in revenues of $111 million attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013.2013 acquisition date.
(b)
2013 amount includes an increase in expense of $30 million attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013 acquisition date, and a $1 millionan increase in expense of $1 million related to hurricane clean-up and repair activities.
(c)
2013 amount includes a $19 million decrease in earnings of $19 million attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013 acquisition date, and a decrease of $1 million decrease in earnings from incremental severance expenses.
(d)
Represents EBDA attributable to our FTC Natural Gas Pipelines disposal group. 2013 amount represents a $2 million loss from the sale of net assets. 2012 amount includes a $322 million loss from the remeasurement of net assets to fair value, and also includes revenues of $71 million.
(e)Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, Tennessee Gas Pipeline L.L.C., El Paso Natural Gas Pipeline Company, L.L.C.,TGP, EPNG, Copano South Texas and the Texas intrastate natural gas pipeline group. Volumes for acquired pipelines are included for all periods.
(e)Represents volumes for the Texas intrastate natural gas pipeline group.
(f)Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Eagle Ford, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.

3642



Combined, the certain items described in the footnotes to the table above (i) increased our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) by $380 million in the first quarter of 2013; and (ii) increased segment revenues (including discontinued operations) by $111 million in the first quarter of 2013, when compared to the year earlier first quarter. Following is information related to the increases and decreases, in the comparable three month periods of 20132014 and 2012 and including discontinued operations, in the segment’s remaining (i) $218 million (78%) increase in EBDA; and (ii) $393 million (45%) increase in operating revenues:

2013:
Three months ended March 31, 2013 versus Three months ended March 31, 2012
 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 (In millions, except percentages)
Tennessee Gas Pipeline$221
 n/a
 $266
 n/a
El Paso Natural Gas Pipeline46
 n/a
 45
 n/a
El Paso Midstream asset operations11
 n/a
 14
 n/a
Eagle Ford Gathering(a)8
 490 % n/a
 n/a
Kinder Morgan Treating operations(5) (28)% (2) (6)%
Texas Intrastate Natural Gas Pipeline Group(4) (4)% 144
 21 %
All others (including eliminations)(2) (2)% (3) (4)%
Total Natural Gas Pipelines-continuing operations275
 124 % 464
 58 %
Discontinued operations(b)(57) (100)% (71) (100)%
Total Natural Gas Pipelines-including discontinued operations$218
 78 % $393
 45 %
Three months ended March 31, 2014 versus Three months ended March 31, 2013
 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 (In millions, except percentages)
Copano operations (excluding Eagle Ford)$80
 n/a
 $463
 n/a
EPNG56
 123% 97
 219 %
TGP35
 16% 39
 15 %
Eagle Ford(a)24
 n/a
 145
 n/a
Texas Intrastate Natural Gas Pipeline Group19
 21% 273
 33 %
EP midstream asset operations12
 103% 37
 271 %
All others (including eliminations)
 % (132) (120)%
Total Natural Gas Pipelines$226
 45% $922
 73 %
____________
n/a – not applicable

(a)Equity investment. We recordinvestment until May 1, 2013. On that date, as part of our Copano acquisition, we acquired the remaining 50% ownership interest that we did not already own. Prior to that date, we recorded earnings under the equity method of accounting, but we receivereceived distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures.
(b)Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

The primary increases and decreases in our Natural Gas Pipelines business segment’s EBDA from continuing operations in the first quarter of 20132014 compared to the first quarter of 20122013 were attributable to the following:
incremental earnings of $221$80 million from our Tennessee Gas Pipeline,Copano operations, which we acquired from KMI effective AugustMay 1, 2012;2013 (but excluding Copano’s 50% ownership interest in Eagle Ford, which is included below with the 50% ownership interest we previously owned);
incremental earnings of $46$56 million from EPNG, due largely to our El Paso Natural Gas Pipeline, whichacquisition of the remaining 50% interest we acquired 50% from KMI effective August 1, 2012, and 50%did not already own from KMI effective March 1, 2013;
incremental earningsa $35 million (16%) increase from TGP, primarily due to higher revenues from (i) firm transportation and storage due largely to new projects placed in service since the end of $11 million from the El Paso midstream assets we acquired 50% from Kohlberg Kravis Roberts & Co. L.P. effective June 1, 2012,first quarter of 2013; (ii) usage and 50% from KMI effective March 1,interruptible transportation services, due to both weather-related increases and higher short-haul volumes; and (iii) natural gas park and loan customer services, due also primarily to colder winter weather relative to the first quarter of 2013;
incremental equity earnings of $8$24 million (490%) from our 50%-ownedtotal (100%) Eagle Ford Gathering LLC,natural gas gathering operations, due mainly to the incremental 50% ownership interest we acquired as part of our acquisition of Copano effective May 1, 2013, and to higher natural gas gathering volumes from the Eagle Ford natural gas shale formation in South Texas;formation;
a $5$19 million (28%(21%) decreaseincrease from our Kinder MorganTexas intrastate natural gas treating operations, primarilypipeline group, due largely to lowerhigher natural gas sales, transportation, and storage margins, from treating equipment manufacturing, and partly due to lower amine treating revenues;all driven in part by colder weather in the first quarter of 2014; and
a $4incremental earnings of $12 million (4%) decrease from our Texas intrastate natural gas pipeline group. The decrease was primarilyEP midstream assets, due largely to lower storage margins, and partly due to lower margins on natural gas processing activities. The decreaseour acquisition from storage activities was due mainly to timing differences on storage settlements, andKMI effective March 1, 2013 of the drop in processing margins was driven by lower natural gas liquids prices. The overall decrease in our intrastate group’s earnings was partiallyremaining 50% interest we did not already own.


3743


offset by higher margins on natural gas sales, due to higher average natural gas sales prices relative to the first quarter of 2012, and higher natural gas delivery volumes to Mexico.
The quarter-to-quarter decrease in earnings before depreciation, depletion and amortization expenses from discontinued operations was due to the sale of our FTC Natural Gas Pipelines disposal group to Tallgrass effective November 1, 2012. For further information about this sale, see Note 1 General—Basis of Presentation—FTC Natural Gas Pipelines Disposal Group – Discontinued Operations” to our consolidated financial statements included elsewhere in this report.
The overall changes in both segment revenues and segment operating expenses (from continuing operations and which include natural gas costs of sales) in the comparable three month periods of 2013 and 2012 primarily relate to the natural gas purchase and sale activities of our Texas intrastate natural gas pipeline group, with the variances from period-to-period in both revenues and operating expenses mainly due to corresponding changes in the intrastate group’s average prices and volumes for natural gas purchased and sold. Our intrastate group both purchases and sells significant volumes of natural gas, which is often stored and/or transported on its pipelines, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases and decreases in its gas sales revenues are largely offset by corresponding increases and decreases in its natural gas purchase costs. We realize earnings by capturing the favorable differences between the changes in its gas sales prices, purchase prices and transportation costs, including fuel. For the comparable first quarter periods of 2013 and 2012 our Texas intrastate natural gas pipeline group accounted for 66% and 86%, respectively, of the segment’s revenues, and88% and 96%, respectively, of the segment’s operating expenses.
CO2 
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues(a)$429
 $417
$483
 $429
Operating expenses(92) (87)(125) (92)
Earnings from equity investments6
 6
7
 6
Income tax expense(1) (2)(2) (1)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments$342
 $334
EBDA363
 342
Certain items(a)3
 (2)
EBDA before certain items$366
 $340
      
Southwest Colorado carbon dioxide production (gross) (Bcf/d)(b)1.2
 1.2
Southwest Colorado carbon dioxide production (net) (Bcf/d)(b)0.5
 0.5
Change from prior periodIncrease/(Decrease)
Revenues before certain items(a)$59
 14%
EBDA before certain items$26
 8%
   
Southwest Colorado CO2 production (gross) (Bcf/d)(b)
1.3
 1.2
Southwest Colorado CO2 production (net) (Bcf/d)(b)
0.6
 0.5
SACROC oil production (gross)(MBbl/d)(c)30.7
 26.9
31.8
 30.7
SACROC oil production (net)(MBbl/d)(d)25.6
 22.4
26.4
 25.6
Yates oil production (gross)(MBbl/d)(c)20.5
 21.2
19.6
 20.5
Yates oil production (net)(MBbl/d)(d)9.1
 9.4
8.7
 9.1
Katz oil production (gross)(MBbl/d)(c)2.1
 1.5
3.5
 2.1
Katz oil production (net)(MBbl/d)(d)1.7
 1.3
2.9
 1.7
Natural gas liquids sales volumes (net)(MBbl/d)(d)10.3
 9
Goldsmith oil production (gross)(MBbl/d)(c)1.2
 n/a
Goldsmith oil production (net)(MBbl/d)(d)1.0
 n/a
NGL sales volumes (net)(MBbl/d)(d)9.9
 10.3
Realized weighted average oil price per Bbl(e)$86.85
 $90.63
$91.89
 $86.85
Realized weighted average natural gas liquids price per Bbl(f)$46.48
 $61.36
Realized weighted average NGL price per Bbl(f)$49.44
 $46.48
____________
n/a – not applicable
(a)
20132014 and 20122013 amounts include unrealized gainslosses of $2$3 million and unrealized lossesgains of $3$2 million, respectively, all relating to derivative contracts used to hedge forecasted crude oil sales.
(b)Includes McElmo Dome and Doe Canyon sales volumes.

38


(c)Represents 100% of the production from the field. We own an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, and an approximately 99% working interest in the Katz Strawn unit and a 100% working interest in the Goldsmith Landreth unit.
(d)Net to us, after royalties and outside working interests.
(e)Includes all of our crude oil production properties.
(f)Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party processing agreements.

Our CO2 segment’s primary businesses involve the production, marketing and transportation of both carbon dioxide (commonly called CO2) and crude oil, and the production and marketing of natural gas and natural gas liquids.NGL. We refer to the segment’s two primary businesses as its Oil and Gas Producing Activities and its Sales and Transportation Activities.

44


The certain items related to unrealized gains and losses on derivative contracts described in footnote (a) to the table above accounted for a $5 million increase in both segment EBDA and revenues in the first quarter of 2013, when compared to the first quarter of 2012. For each of the segment’s two primary businesses, following is information related to the increases and decreases, in the comparable three month periods of 20132014 and 2012, in the segment’s remaining (i)$3 million (1%) increase in EBDA; and (ii) $7 million (2%) increase in operating revenues:2013

:
Three months ended March 31, 2013 versus Three months ended March 31, 2012
Three months ended March 31, 2014 versus Three months ended March 31, 2013Three months ended March 31, 2014 versus Three months ended March 31, 2013
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Sales and Transportation Activities$5
 6 % $4
 5 %$20
 22% $26
 25 %
Oil and Gas Producing Activities(2) (1)% 5
 1 %6
 2% 38
 11 %
Intrasegment eliminations
  % (2) (16)%
 % (5) (29)%
Total CO2
$3
 1 % $7
 2 %$26
 8% $59
 14 %

The quarter-to-quarter increase in earnings before depreciation, depletion and amortization expensesEBDA from the segment’s sales and transportation activities was driven by (i) higher reimbursable project revenues,primarily revenue related, largely relatedattributable to the completion of prior expansion projects on the Central Basin pipeline system; (ii) higher third party storage revenues at the Yates field unit; and (iii) higher carbon dioxide sales revenues, due to a 1%following: 
a $24 million (34%) increase in CO2 sales revenues driven byan 18% increase in average sales prices. The increase in sales prices was due primarily to two factors: (i) a change in the mix of contracts resulting in more CO2 being delivered under higher price contracts; and (ii) heavier weighting of new CO2 contract prices to the price of crude oil. CO2 sales volumes were also higher by 14% in the first quarter of 2014 versus the first quarter of 2013.

The quarter-to-quarter increase in total carbon dioxide sales volumes. 
Earnings for the comparable three month periods of 2013 and 2012EBDA from the segment’s oil and gas producing activities, decreased slightly (1%)which include the operations associated with the segment’s ownership interests in the first quarter of 2013, versus the same quarter a year ago. The $5 million (1%) increase in operating revenuesoil-producing fields and natural gas processing plants, was offset by a $7 million (8%) increase in combined operating expenses, driven by an almost $5 million increase in well workover expenses. The increase in workover expenses waslargely due to both increased drilling activity, relative to the first quarter of 2012, and higher prices charged by the industry’s material and service providers, which impacted rig costs. The overall $5 million (1%) quarter-to-quarter increase in oil and gas related revenues included an $11 million (4%) increase in crude oil sales revenues (due to a 9% increase in sales volumes), partially offset by a $7 million (14%) decrease in plant product sales revenues (reflecting a 24% drop in our realized weighted average price per barrel of natural gas liquids)following:
a $37 million (13%) increase from higher crude oil sales revenues, due primarily to 6% increase in our realized weighted average price per barrel of crude oil, and partly due to higher oil sales volumes. Overall crude oil sales volumes increased 7% in the first quarter of 2014, when compared to the first quarter last year. The increase in sales volumes was due primarily to higher production at the Katz field unit, incremental production from the Goldsmith Landreth unit (acquired effective June 1, 2013), and higher production at the SACROC unit (volumes presented in the results of operations table above). The increase in revenue was partially offset by an increase in power costs that was due to higher gas and water volumes and market pricing. In addition, operating costs increased due to higher property taxes and severance taxes related to the increase in revenue. Incremental well work-over costs at our recently acquired Goldsmith property also contributed to an increase in operating expenses.


3945


Products Pipelines
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues$454
 $223
$534
 $454
Operating expenses(a)(281) (57)(339) (281)
Other income(b)
 14
3
 
Earnings from equity investments18
 2
17
 18
Interest income and Other, net(1) 
Income tax expense(6) (6)(6) (6)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments$185
 $176
EBDA208
 185
Certain items, net(a)(b)(4) 15
EBDA before certain items$204
 $200
      
Gasoline (MMBbl)(b)97.8
 95.1
Change from prior periodIncrease/(Decrease)
Revenues$80
 18%
EBDA before certain items$4
 2%
   
Gasoline (MMBbl)(c)103.0
 97.8
Diesel fuel (MMBbl)32.8
 33.6
35.6
 32.8
Jet fuel (MMBbl)27.2
 26.9
27.4
 27.2
Total refined product volumes (MMBbl)(c)157.8
 155.6
Natural gas liquids (MMBbl)(d)9.8
 7.4
Condensate (MMBbl)(e)2.0
 
Total refined product volumes (MMBbl)(d)166.0
 157.8
NGL (MMBbl)(e)8.8
 9.8
Condensate (MMBbl)(f)4.6
 2.0
Total delivery volumes (MMBbl)169.6
 163.0
179.4
 169.6
Ethanol (MMBbl)(f)8.7
 7.3
Ethanol (MMBbl)(g)9.7
 8.7
_______________________
(a)
2014 amount includes a $1 million decrease in expense associated with capitalized overhead costs associated with a certain Pacific operations litigation matter. 2013 amount includes a $15 million increase in expense associated with a legalrate case liability adjustment related to a certain West Coast terminal environmental matter.
(b)2014 amount represents a gain from the sale of propane pipeline line-fill.
(c)Volumes include ethanol pipeline volumes.
(c)(d)Includes Pacific, Plantation Pipe Line Company, Calnev, and Central Florida and Parkway pipeline volumes.
(d)(e)Includes Cochin and Cypress pipeline volumes.
(e)(f)Includes Kinder Morgan Crude Oil & Condensate and Double Eagle pipeline volumes.
(f)(g)Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.

46



The certain item described in footnote (a) to the table above accounted for a $15 million decrease in segment EBDA in the first quarter of 2013, when compared to the same quarter of 2012. Following is information related to the increases and decreases, in the comparable three month periods of both years, in the segment’s (i) remaining $24 million (14%) increase in EBDA;2014 and (ii) $231 million (104%) increase in operating revenues:2013:
Three months ended March 31, 2013 versus Three months ended March 31, 2012
Three months ended March 31, 2014 versus Three months ended March 31, 2013Three months ended March 31, 2014 versus Three months ended March 31, 2013
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Crude & Condensate Pipeline$5
 111 % $23
 453 %
Transmix operations3
 23 % 51
 23 %
Southeast terminal operations2
 11 % 5
 18 %
Parkway Pipeline2
 186 % (1) (78)%
Cochin Pipeline$14
 93 % $13
 67%(5) (18)% (6) (19)%
Transmix operations6
 76 % 212
 n/a
Crude & Condensate Pipeline3
 197 % 5
 n/a
Plantation Pipeline2
 14 % 
 
Pacific operations(3) (5)% 2
 2 %
West Coast terminal operations(2) (9)% (2) (5)%
All others (including eliminations)(1) (1)% 1
 
2
 5 % 8
 21 %
Total Products Pipelines$24
 14 % $231
 104%$4
 2 % $80
 18 %


40


The primary increases and decreases in our Products Pipelines business segment’s EBDA in the comparable three month periods of 20132014 and 20122013 included the following:
a $14$5 million (93%(111%) increase from our Cochin Pipeline. The increase was largely revenue related, reflectingKinder Morgan Crude Oil & Condensate Pipeline, due mainly to a 103%63% increase in pipeline throughput volumes, driven by incremental ethane/propane volumes as a result of pipeline modification projects completed in June 2012;volumes;
a $6$3 million (76%(23%) increase from our transmix processing operations. Theoperations due to higher volumes and margins at various transmix sales plants;
a $2 million (11%) increase wasfrom our Southeast terminal operations, driven by higher margins on processing volumes, due mainly to favorable pricing, and by incremental earnings from third-party sales of excess renewable identification numbers (RINS), generated through our ethanol blending operations. The quarter-to-quarter increase in revenues was due mainly to the expiration of certain transmix fee-based processing agreements in March 2012. Due to the expiration of these contracts, we now directly purchase incremental transmix volumes and sell incremental volumes of refined products, resulting in both higher revenues and higher costs of sales expenses;physical inventory gains;
incremental earnings of $3$2 million from our Kinder Morgan Crude Oil & Condensate50%-owned Parkway Pipeline, which began transporting crude oilwas placed into service in September 2013;
a $5 million (18%) decrease from our Cochin Pipeline, primarily due to lower terminal, storage and condensatepetrochemical volumes and associated revenues;
a $3 million (5%) decrease from our Pacific operations, due primarily to an unfavorable settlement of a certain litigation matter in the Eagle Ford shale gas formation in South Texas to multiple terminaling facilities along the Texas Gulf Coast in October 2012;first quarter of 2014; and
a $2 million (14%(9%) increasedecrease from our approximate 51% interest in the Plantation pipeline system—West Coast terminal operations, due largely to higher transportation revenues driven by both a 10% increase in system delivery volumes and higher average tariff rates since the end of the first quarter of 2012.primarily from lower volumes.


47


Terminals
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues$337
 $341
$391
 $337
Operating expenses(a)(157) (160)(183) (157)
Other expense(b)(1) 
Earnings from equity investments7
 6
5
 7
Interest income and Other, net1
 
1
 1
Income tax expense(2) 
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments$186
 $187
Income tax benefit (expense)(c)1
 (2)
EBDA214
 186
Certain items, net(a)(b)(c)14
 1
EBDA before certain items$228
 $187
      
Bulk transload tonnage (MMtons)(b)22.2
 25.0
Change from prior periodIncrease/(Decrease)
Revenues$54
 16%
EBDA before certain items$41
 22%
   
Bulk transload tonnage (MMtons)(d)21.6
 22.4
Ethanol (MMBbl)15.2
 17.9
16.5
 15.2
Liquids leaseable capacity (MMBbl)60.7
 59.8
71.6
 60.5
Liquids utilization %(c)95.4% 95.7%
Liquids utilization %(e)94.4% 95.1%
__________
(a)
2014 and 2013 amount includes a amounts include increases in expense of $7 million and $1 million, increase in expenserespectively, related to hurricane clean-up and repair activities at our New York Harbor and Mid-Atlantic terminals.
2014 amount also includes a $10 million increase in expense primarily associated with a legal liability adjustment related to a certain litigation matter.
(b)2014 amount represents a casualty indemnification loss, related to 2012 hurricane activity at our New York Harbor and Mid-Atlantic terminals.
(c)2014 amount includes a $4 million decrease in expense (representing tax savings) related to the pre-tax expense amount associated with the litigation matter mentioned in footnote (a).
(d)Volumes for acquired terminals are included for all periods and include our proportionate share of joint venture tonnage.
(c)(e)The ratio of our actual leased capacity (excluding the capacity of tanks out of service) to our estimated potential capacity.

Our Terminals business segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities.Including the certain item described in footnote (a) to the table above, which decreased segment EBDA by $1 million in the first quarter of 2013 compared to the first quarter of 2012,

41


earnings before depreciation, depletion and amortization expenses from our Terminals segment were flat across both comparable first quarter periods of 2013 and 2012.
Following is information related to the increases and decreases, in the comparable three month periods of both years, in the segment’s (i) EBDA (with no net overall change);2014 and (ii) $4 million (1%) decrease in operating revenues:

2013:
Three months ended March 31, 2013 versus Three months ended March 31, 2012
 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 (In millions, except percentages)
West$3
 23 % $4
 15 %
Northeast2
 8 % 
  %
Gulf Bulk(3) (18)% (6) (16)%
Ethanol(2) (27)% (2) (20)%
All others (including intrasegment eliminations and unallocated income tax expenses)
  % 
  %
Total Terminals$
  % $(4) (1)%
The overall increases in earnings before depreciation, depletion and amortization from our Terminals segment was driven by higher contributions from West region terminals, due primarily to (i) incremental volumes from customer agreements at our Kinder Morgan Vancouver Wharves bulk marine terminal; (ii) higher capitalized overhead expenses due to ongoing terminal expansion projects; (iii) higher petroleum throughputs at our North 40 Edmonton, Canada facility; and (iv) higher soda ash volumes at our Portland, Oregon bulk terminal.
Three months ended March 31, 2014 versus Three months ended March 31, 2013
 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 (In millions, except percentages)
Acquired assets and businesses$13
 n/a
 $22
 n/a
Gulf Liquids9
 19% 8
 13 %
West7
 37% 10
 31 %
Gulf Bulk5
 38% 7
 22 %
Gulf Central4
 118% 9
 989 %
All others (including intrasegment eliminations and unallocated income tax expenses)3
 2% (2) (1)%
Total Terminals$41
 22% $54
 16 %

The increase in earnings from our Northeast terminal operations was driven by additional and restructured customer contracts at higher rates, and by an overall increase in chemical volumes. For all terminals combined, we also benefited from a 12% increase in export coal volumes, although we continued to experience weakness in domestic coal volumes. and we experienced lower business activity at various terminal sites primarily involved in the handling and storage of steel and alloy products, when compared to the first quarter of 2012.
Earnings before depreciation, depletion and amortization from both our Gulf Bulk and Ethanol handling terminals decreased in the first quarter of 2013 compared to the first quarter of 2012. The decrease from our Gulf Bulk facilities was driven by lower volumes from petroleum coke handling operations, due in large part to refinery and coker shutdowns as a result of turnarounds taken in the first quarter of 2013. The decrease in revenues and handling volumes from our combined Ethanol terminals was primarily due to the conversion to crude and vegetable oil at two terminals that handled ethanol, along with a decline in volumes at our coastal facilities attributable to increased import barrels. For all terminals included in our Terminals business segment, total ethanol handling volumes dropped 15% in the first quarter of 2013 compared to the first quarter of 2012.

4248


The primary increases and decreases in our Terminals business segment’s EBDA in the comparable three month periods of 2014 and 2013 included the following:
The $13 million increase from acquired assets and businesses relates primarily to the incremental earnings for the marine operations we acquired effective January 17, 2014 (our APT acquisition).
The higher earnings from our Gulf Liquids terminals were mainly due to higher liquids warehousing revenues from our Pasadena and Galena Park liquids facilities located along the Houston Ship Channel. The facilities benefited from high gasoline export demand, increased rail services, and new and incremental customer agreements at higher rates, including new tankage from our expansion projects.
We also realized higher quarter-to-quarter earnings in 2014 from our West region terminals (driven by the completion of expansion projects since the end of the first quarter of 2013), our Gulf Bulk terminals (driven by higher volumes in the first quarter of 2014, due in large part to refinery and coker shutdowns in the first quarter of 2013 as a result of turnarounds taken), and our Gulf Central terminals (driven by higher earnings from BOSTCO, our oil terminal joint venture, of which we own approximately 55%, located on the Houston Ship Channel that began operations in October 2013).

Kinder Morgan Canada
Three Months Ended
March 31,
Three Months Ended
March 31,
2013 20122014 2013
(In millions, except operating statistics)(In millions, except operating statistics)
Revenues$72
 $73
$69
 $72
Operating expenses(25) (24)(24) (25)
Earnings from equity investments4
 1

 4
Interest income and Other, net(a)230
 3
7
 230
Income tax expense(b)(88) (3)(4) (88)
Earnings before depreciation, depletion and amortization expense and amortization of excess cost of equity investments$193
 $50
EBDA48
 193
Certain items, net(a)(b)
 (141)
EBDA before certain items$48
 $52
   
Change from prior periodIncrease/(Decrease)
Revenues$(3) (4)%
EBDA before certain items$(4) (8)%
      
Transport volumes (MMBbl)(c)26.7
 24.9
25.0
 26.7
__________
(a)
2013 amount includes a gain of $225 million gain from the sale of our equity and debt investments in the Express pipeline system.
(b)
2013 amount includes anincrease of $84 million increase in expense related to the pre-tax gain amount associated with the sale of our equity and debt investments in the Express pipeline system described in footnote (a).
(c)Represents Trans Mountain pipeline system volumes.

Our Kinder Morgan Canada business segment includes the operations of our Trans Mountain and Jet Fuel pipeline systems, and until March 14, 2013, the effective date of sale, our one-third ownership interest in the Express crude oil pipeline system. The certain items relating to our sale of Express described in the footnotes to the table above increased segment earnings before depreciation, depletion and amortization by $141 million in the first quarter of 2013, when compared to the same quarter last year. For each of the segment’s three primary businesses, followingFollowing is information related to the increases and decreases, in the comparable three month periods of 20132014 and 2012, related to the segment’s (i) remaining $2 million (4%) increases in EBDA; and (ii) $1 million (1%) decrease in operating revenues:2013:
Three months ended March 31, 2013 versus Three months ended March 31, 2012
Three months ended March 31, 2014 versus Three months ended March 31, 2013Three months ended March 31, 2014 versus Three months ended March 31, 2013
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
(In millions, except percentages)(In millions, except percentages)
Trans Mountain Pipeline$1
 1% $(1) (1)%$(4) (7)% $(3) (4)%
Express Pipeline(a)1
 34% n/a
 n/a

  % n/a
 n/a
Jet Fuel Pipeline
 % 
  %
  % 
  %
Total Kinder Morgan Canada$2
 4% $(1) (2)%$(4) (8)% $(3) (4)%
__________

49


(a)Equity investment; accordingly, we recorded earnings under the equity method of accounting. However, we sold our debt and equity investments in Express effective March 14, 2013.

The decrease in Trans Mountain’s earnings was driven by a $5 million unfavorable impact from foreign currency translation. Due to the weakening of the Canadian dollar since the end of the first quarter of 2013, we translated Canadian denominated income and expense amounts into fewer U.S. dollars in 2014.

Other
 Three Months Ended
March 31,
 2014 2013
 (In millions)
General and administrative expenses(a)$153
 $134
    
Interest expense, net of unallocable interest income(b)$239
 $202
    
Unallocable income tax expense$2
 $3
    
Net income attributable to noncontrolling interests(c)$8
 $9
__________
(a)Equity investment. We record earnings under the equity method of accounting.

Earnings before depreciation, depletion and amortization expenses from our Kinder Morgan Canada business segment were essentially unchanged across both comparable first quarter periods of 2013 and 2012. The quarter-to-quarter increase in Trans Mountain’s earnings before depreciation, depletion and amortization expenses was mainly due to both higher non-operating income, related to incremental management incentive fees earned from its operation of the Express pipeline system, and to increased deliveries into Washington state on our Puget sound pipeline system. The increase in earnings from our equity investment in the Express pipeline system was primarily due to volumes moving at higher transportation rates on the Express portion of the system (on both Canadian and U.S delivery volumes).


43


Other
 Three Months Ended
March 31,
 2013 2012
 (In millions)
General and administrative expenses(a)$134
 $107
    
Interest expense, net of unallocable interest income(b)$202
 $139
    
Unallocable income tax expense$3
 $2
    
Net income attributable to noncontrolling interests(c)$9
 $2
__________

(a)
20132014 amount includes (i) a $6 million increase in severance expense allocated to us from KMI (associated with both our March 2013 asset drop-down group and assets we acquired from KMI in August 2012; however, we do not have any obligation, nor did we pay any amounts related to this expense); (ii) a $1 million increase in expense associated with unallocated business acquisition costs; and (iii) a $1 million decrease in expense associated with capitalized overhead costs related to a certain Pacific operations litigation matter. 2013 amount also includes (i) a $9 million increase in expense attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013;2013 acquisition date; (ii) a $4 million increase in expense associated with unallocated legal expenses and certain asset and business acquisition costs; and (iii) a $1 million increase in severance expense allocated to us from KMI (associated with both theour March 2013 asset drop-down group and assets we acquired from KMI in August 2012);2012; however, we do not have any obligation, nor did we pay any amounts related to this expense. 2012 amount includes a $1 million increase in unallocated severance expense associated with certain Terminal operations.expense).

(b)
2014 amount includesa $13 million increase in interest expense associated with a certain Pacific operations litigation matter, and a $2 million decrease in interest expense associated with debt fair value adjustments recorded in purchase accounting for our Copano acquisition. 2013 amount includes a $15 million increase in interest expense attributable to our March 2013 drop-down asset group for periods prior to our acquisition date of March 1, 2013.2013 acquisition date.

(c)
2013 and amount includes2012 amounts include an increase ofa $2 million and a decrease of $4 million, respectively,increase in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2013 and 2012 certain items previously disclosed in the footnotes to the tables included above in “—Results of Operations.”

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

These expenses are generally not controllable by our business segment operating managers and therefore are not included when we measure business segment operating performance. For this reason, and because we manage our business based on our reportable business segments and not on the basis of our ownership structure, we do not specifically allocate our general and administrative expenses to our business segments. As discussed previously, we use segment EBDA internally as a measure of profit and loss used for evaluatingto evaluate segment performance, and each of our segment’s EBDA includes all costs directly incurred by that segment.

The certain items described in footnote (a) to the table above accounted for a $13an$8 million increasedecrease in our general and administrative expenses in the first quarter of 2013,2014, when compared to the same quarter aprior year ago.period. The remaining $14$27 million (13%(23%) quarter-to-quarter increase in expense was largely driven by the acquisition of additional businesses, associated primarily associated with theour acquisition of our Tennessee Gas Pipeline from KMI effective Augustboth Copano (effective May 1, 2012,2013) and partly associated with the acquisition of ourMarch 2013 drop-down asset group from KMI effective(effective March 1, 2013.2013). Additional drivers were increased benefits costs and higher segment labor.

WeIn the table above, we report our interest expense as “net,” meaning that we have subtracted unallocated interest income and capitalized interest from our interest expense to arrive at one interest amount, and after taking into effect the certain itemitems described in footnote (b) to the table above, our netunallocable interest expense increased by $48$41 million (35%(22%) in the first quarter of 2013,2014, when compared withto the first quarter of 2012.2013. The increase was driven by a 31% increase in ourhigher average debt balance

50


levels (average borrowings for the first three months of 2013, versusmonth period ended March 31, 2014 increased 16%, when compared to the same period a year earlier period. Our higher average borrowings wasago), largely due to the capital expenditures, business acquisitions (including debt assumed from the drop-down transaction), and joint venture contributions and business acquisitions we have made since the end of the first quarter of 2012. We also realized an 8% increase in the2013. The weighted average interest rate on all of our borrowings in the first three months of 2013, when compared to the first quarter last

44


year. Includingborrowings—including both short-term and long-term borrowing amounts, our average interest rate increased from 4.23% for the first quarter of 2012 toamounts—was essentially flat across both three month periods (from 4.57% for the first quarter of 2013.2013to4.60% for the first quarter of 2014).
We swap a portion of our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of March 31, 20132014 and December 31, 2012,2013, approximately 35%27% and 37%29%, respectively, of our consolidated debt balances (excluding our debt fair value adjustments) waswere subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swap agreements. For more information about our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements included elsewhere in this report.statements.

Financial Condition
General
As of March 31, 2013,2014, we had $736$347 million of “Cash and cash equivalents” on our consolidated balance sheet, (included elsewhere in this report), an increasea decrease of $207$57 million (39%(14%) from December 31, 2012.2013. We also had, as of March 31, 2013,2014, approximately $1.42.1 billion of borrowing capacity available under our $2.2$2.7 billion senior unsecured revolving credit facility (discussed below in “—Short-term Liquidity”). We believe our cash position and our remaining borrowing capacity is adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
Our primary cash requirements, in addition to normal operating expenses, are for debt service, sustaining capital expenditures, (defined as capital expenditures which do not increase the capacity of an asset), expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholder and general partner.
In general, we expect to fund:
cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;
expansion capital expenditures and working capital deficits with retained cash (which may result from including i-units in the determination of cash distributions per unit but paying quarterly distributions on i-units in additional i-units rather than cash), proceeds from divestitures, additional borrowings (including commercial paper issuances), and the issuance of additional common units or the proceeds from purchases of additional i-units by KMR;
interest payments with cash flows from operating activities; and
debt principal payments, as such debt principal payments become due, with proceeds from divestitures, additional borrowings or by the issuance of additional common units or the proceeds from purchases of additional i-units by KMR.

In addition to our results of operations, our debt and capital balances are affected by our financing activities, as discussed below in “—Financing Activities.”
Credit Ratings and Capital Market Liquidity
Currently, Cash provided from our long-term corporate debt credit ratingoperations is BBB (stable), Baa2 (stable) and BBB (stable), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch, Inc., respectively. Our short-term corporate debt credit rating is A-2 (susceptible to adverse economic conditions, however, capacity to meet financial commitments is satisfactory), Prime-2 (strong ability to repay short-term debt obligations) and F2 (good quality grade with satisfactory capacity to meet financial commitments), at Standard & Poor’s Ratings Services, Moody’s Investors Service, Inc. and Fitch, Inc., respectively. Our credit ratings affect our ability to access the commercial paper market and the public and private debt markets, as well as the terms and pricingfairly stable across periods since a majority of our debt. Based on these credit ratings,cash generated is fee based from a diversified portfolio of assets and is not sensitive to commodity prices. However, in our CO2 business segment, while we expect thathedge the majority of our short-term liquidity needs will be met primarily through borrowings under our commercial paper program. Nevertheless, our abilityoil production, we do have exposure to satisfy our financing requirements or fund our planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the energy pipeline and terminals industries and other financial and business factors, someunhedged volumes, a significant portion of which are beyond our control.NGL.

45


Short-term Liquidity

As of March 31, 2013,2014, our principal sources of short-term liquidity were (i) our $2.2$2.7 billion senior unsecured revolving credit facility with a diverse syndicate of banks that matures JulyMay 1, 2016;2018; (ii) our $2.2$2.7 billion short-term commercial paper program (which is supported by our credit facility, with the amount available for borrowing under our credit facility being reduced by our outstanding commercial paper borrowings and letters of credit); and (iii) cash from operations (discussed below in “—Operating Activities”). The loan commitments under our revolving credit facility can be used to fund borrowings for general partnership purposes and as a backup for our commercial paper program, and our credit facility can be amended to allow for borrowings of up to $2.5 billion.program. As of both March 31, 20132014 and December 31, 2012,2013, we had no outstanding borrowings under our credit facility.facility borrowings.

Our outstanding short-term debt as of March 31, 20132014 was$1,1271,243 million, primarily consisting of (i)$595419 million of outstanding commercial paper borrowings; and (ii) $500 million in principal amount of 5.00%5.125% senior notes that mature December

51


November 15, 2013.2014; and (iii) $300 million in principal amount of 5.625% senior notes that mature February 15, 2015. We intend to refinance our current short-term debt through a combination of long-term debt, equity, and/or the issuance of additional commercial paper or credit facility borrowings to replace maturing commercial paper and current maturities of long-term debt. As of December 31, 2012,2013, our short-term debt totaled $1,1551,504 million.

We had a working capital deficit of $8321,516 million as of March 31, 2013,2014, and a working capital deficit of $870$1,909 million as of December 31, 2012.2013.  The overall $38393 million (4%(21%) favorable change from year-end 20122013 was primarily due to the $207 million increase in “Cashlower short-term debt balance (discussed above), and cash equivalents” described above in —General,” and partially offset by a $179 million decrease in working capital due to the removal of our equity and debt investments in the Express pipeline system from current assets held for sale (we sold our investments in Express in March 2013).lower accrued interest liabilities. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in cash and cash equivalent balances as a result of debt or equity issuances (discussed below in “—Long-term Financing”).

Long-term Financing
In addition to our principal sources of short-term liquidity listed above, we could meet our cash requirements (other than distributions of cash from operations to our common unitholders, Class B unitholder and general partner) through issuing long-term debt securities or additional common units, or by utilizing the proceeds from purchases of additional i-units by KMR with the proceeds from issuances of KMR shares.
Our equity offerings consist of the issuance of additional common units or the issuance of additional i-units to KMR (which KMR purchases with the proceeds from the sale of additional KMR shares). As a publicly traded limited partnership, our common units are attractive primarily to individual investors, although such investors represent a small segment of the total equity capital market. We believe that some institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations, and we are able to access this segment of the capital market through KMR’s purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutional investors. For more information about our equity issuances in the first three monthsquarter of 2013,2014, see Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report.statements.

From time to time we issue long-term debt securities, often referred to as our senior notes. Our senior notes issued to date, other than those issued by our subsidiaries and operating partnerships, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations; however, a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries.obligations. Our fixed rate senior notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. As of March 31, 2014 and December 31, 2013, the aggregate principal amount of the various series of our senior notes was$17,100 million and $15,600 million, respectively.

In addition, from time to time our subsidiaries Tennessee Gas Pipeline Company, L.L.C. and El Paso Natural Gas Company, L.L.C. have issued long-term debt securities, often referred to as their senior notes. Most of the debt of our operating partnerships and subsidiaries is unsecured; however a modest amount of secured debt has been incurred by some of our operating partnerships and subsidiaries. As of March 31, 2013, Tennessee Gas Pipeline Company, 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. The interest rates on these notes range from 7% per annum through 8.375% per annum, and the maturity dates range from February 2016 through April 2037. El Paso Natural Gas Company, L.L.C. is the obligor of four separate series of fixed-rate unsecured senior notes having a combined principal amount of

46


$1,115 million. The interest rates on these notes range from 5.95% per annum through 8.625% per annum, and the maturity dates range from April 2017 through June 2032.
2014As of March 31, 2013 and December 31, 2012, the aggregate principal amount of the various series of our senior notes was $14,350 million and $13,350 million, respectively, and2013, the total liability balance due on the various borrowings of our operating partnerships and subsidiaries (including both Tennessee Gas Pipeline Company, L.L.C.’s and El Paso Natural Gas Company, L.L.C.’s senior notes discussed above)notes) was $3,0113,334 million and $3,0913,335 million, respectively.

To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt relateddebt-related transactions in the first three monthsquarter of 2014 and our consolidated debt obligations as of both March 31, 2014 and December 31, 2013, see Note 3 “Debt” to our consolidated financial statements included elsewhere in this report.statements. For additional information regarding our debt securities, see Note 15 “Reportable Segments”8 “Debt” to our consolidated financial statements included in our 20122013 Form 10-K.

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

Capital Expenditures
We define account for our capital expenditures in accordance with GAAP. Capital expenditures under our partnership agreement include those that are maintenance/sustaining capital expenditures and those that are capital additions and improvements (which we refer to as expansion or discretionary capital expenditures). These distinctions are used when determining cash from operations pursuant to our partnership agreement (which is distinct from GAAP cash flows from operating activities). Capital additions and improvements are those expenditures which increase throughput or capacity

52


from that which existed immediately prior to the addition or improvement, and are not deducted in calculating cash from operations. Maintenance capital expenditures are those which maintain throughput or capacity. Thus under our partnership agreement, the distinction between maintenance capital expenditures and capital additions and improvements is a physical determination rather than an economic one.

Generally, the determination of whether a capital expenditure is classified as maintenance or as capital additions and improvements is made on a project level. The classification of capital expenditures as capital additions and improvements or as maintenance capital expenditures under our partnership agreement is left to the good faith determination of the general partner, which do not increaseis deemed conclusive.
Our capital expenditures for the capacitythree months ended March 31, 2014, and the amount we expect to spend for the remainder of an asset2014 to grow and sustain our businesses are as follows (in millions):
 Three Months Ended
March 31, 2014
 
2014
Remaining
 Total
Sustaining(a)$72
 $374
 $446
Discretionary(b)(c)710
 3,211
 3,921
Total$782
 $3,585
 $4,367
  —————————
(a)Three month 2014 amount, 2014 remaining amount, and total 2014 amount include $1 million, $5 million and $6 million, respectively, for our proportionate share of sustaining capital expenditures of our unconsolidated joint ventures.
(b)Three month 2014 amount (i) includes $66 million of discretionary capital expenditures of our unconsolidated joint ventures and acquisitions; and (ii) excludes a combined $94 million net change from accrued capital expenditures, contractor retainage and amounts primarily related to contributions from our noncontrolling interests to fund a portion of certain capital projects.
(c)2014 remaining amount includes our contributions to certain unconsolidated joint ventures and small acquisitions, net of contributions estimated from unaffiliated joint venture partners for consolidated investments.

We generally we fund our sustaining capital expenditures with existing cash or from cash flows from operations. For the first three months of 2013 and 2012, our sustaining capital expenditures totaled $48 million and$44 million, respectively (the first quarter 2012 amount included$2 million for our proportionate share of the sustaining capital expenditures of our unconsolidated joint ventures). We forecasted $339 million for sustaining capital expenditures in our 2013 budget. This amount includes $6 million for our proportionate share of our unconsolidated joint ventures’ sustaining capital expenditures.
In addition to the sustaining capital expenditures described above (excluding our proportionate share of the first quarter 2012 sustaining capital expenditures of our unconsolidated joint ventures), our consolidated statements of cash flows for the three months ended March 31, 2013 and 2012 included capital expenditures of $504 million and$311 million, respectively. We report our total consolidated capital expenditures separately as Capital expenditures within the Cash Flows from Investing Activities section on our accompanying cash flow statements (included elsewhere in this report), and the overall$199 million (56%) quarter-to-quarter increase in our consolidated capital expenditures in 2013 versus 2012 was primarily due to higher investment undertaken to expand and improve our Terminals, Natural Gas Pipelines, and CO2business segments. Generally, we initially fund our discretionary capital expenditures through borrowings under our commercial paper program or our revolving credit facility until the amount borrowed is of a sufficient size to cost effectively offer eitherreplace the initial funding with long-term debt, equity (including retained cash related i-unit distributions), or both.
Capital Requirements for Recent Drop-Down Transaction
In the first quarter of 2013,We report our cash outlays for the drop-down transaction totaled $988 million and we reported this amounttotal consolidated capital expenditures separately asCapital expenditureswithin theCash Flows Fromfrom Investing Activities—Payment to KMI for drop-down asset group”Activitiessection on our accompanying consolidated statement of cash flows included elsewhere in this report. With the exception of our partial paymentflow statements, and for each of the combined purchase price to KMI by the issuance of addition common units (discussed following), we funded this $988 million acquisition payment with proceeds received from (i) our Februarythree months ended March 31, 2014 and 2013, issuance of long-term senior notes; (ii) our February 2013 public offering of additional common units; and (iii) borrowings under our commercial paper program.
We also issued an aggregate consideration ofthese amounts totaled $108809 million and $552 million, respectively. The overall$257 million (47%) quarter-to-quarter increase in common unitsour consolidated capital expenditures in 2014 versus 2013 was primarily due to KMI in the first quarter of 2013 as partial payment for the drop-down asset group. We reported this amount separately as “Noncash Investinghigher investment undertaken to expand and Financingimprove our

47


Activities—Assets acquired or liabilities settled by the issuance of common units” on our accompanying consolidated statement of cash flows included elsewhere in this report.Products Pipelines, Natural Gas Pipelines and Kinder Morgan Canadabusiness segments.

Additional Capital Requirements
In April 2012, we announced that we were proceeding with our proposal to expand our existing Trans Mountain pipeline system. When completed, the proposed expansion will increase capacity on Trans Mountain from its current 300,000 barrels per day300 MBbl/d of crude oil and refined petroleum products to approximately 890,000 barrels per day.890 MBbl/d. In 2012,December 2013, we confirmed binding commercial supportfiled a Facilities Application with the NEB to receive authorization to build and operate the necessary facilities for the proposed expansion project. The NEB recently issued a hearing order for the proposed project, and we expect public hearings to begin this summer and an NEB decision by July 2015. Failure to secure NEB approval of this project and pending the filing and approval of tolling and facilities applications with Canada’s National Energy Board (NEB),on reasonable terms could require us to either delay or cancel this project; however, if approvals are received as planned, we expect to begin construction in 2015 or 2016, with the proposed project beginningand begin operations in late 2017. Our current estimate of total construction costs on the project is approximately$5.4 billion. Trans Mountain is currently
On March 26, 2014, we announced that we will build and operate a new, 213-mile, 16-inch diameter pipeline to transport carbon dioxide from our St. Johns source field located in Apache County, Arizona, to Cortez Pipeline, which we operate and of which we own 50%, in Torrance County, New Mexico. The new Lobos Pipeline will have an initial capacity of 300 million standard cubic feet per day and will support current and future enhanced oil recovery projects owned by us and other operators in the final stagesPermian Basin of securing NEB approval for the commercial terms of the expansion. FailureWest Texas and eastern New Mexico. We plan to secure NEB approval of this project at a reasonable toll rate could require us to either delay or cancel this project.  We anticipate NEB’s approvalinvest approximately $300 million in the secondpipeline and an additional $700 million to drill wells and build field gathering,

53


treatment and compression facilities at the St. Johns field. We expect to place the project into service by the third quarter of 2013.
2016, pending receipt of environmental and regulatory approvals.
In addition, we regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions. Such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. For the year 2013, we expect to invest over $3 billion for our capital expansion program, which includes small acquisitions and contributions to joint ventures, but excludes acquisitions from KMI. Our previously announced acquisition of Copano will be a 100% unit for unit transaction. For more information about our asset acquisitions from KMI and our announced acquisition of Copano, see Note 2 “Acquisitions and Divestitures” to our consolidated financial statements included elsewhere in this report.
Our ability to make accretive acquisitions (i) is a function of the availability of suitable acquisition candidates at the right cost; (ii)expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions; and (iii) includes factors over which we have limited or no control. Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates. Our ability to expand our assets is also impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such expansions.

As a master limited partnership,an MLP, we distribute all of our available cash (except to the extent that we retain cash from the payment of distributions on i-units in additional i-units), and we access capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, our investment grade credit rating, and our historical record of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, distribution and acquisition strategies, as well as refinance maturing debt when required.

Off Balance Sheet Arrangements
Operating ActivitiesThere have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2013 in our 2013 Form 10-K.

NetCash Flows

The following table summarizes our net cash provided byflows from operating, investing and financing activities was $746 million for each of the three months ended March 31, 2013, versus $6582014 and 2013:
 
Three Months Ended
 March 31,
  
 2014 2013 
Cash
increase/(decrease)
 (In millions)
Net Cash Provided by (Used in):     
Operating activities$1,074
 $746
 $328
Investing activities(1,801) (1,171) (630)
Financing activities680
 638
 42
Effect of exchange rate changes on cash and cash equivalents(10) (6) (4)
Net (Decrease) Increase in Cash and Cash Equivalents$(57) $207
 $(264)

Operating Activities

The overall $328 million for the same comparable period of 2012. The quarter-to-quarter(44%) increase of$88 million (13%) in cash flowflows provided from operations was due toour operating activities in the first quarter of 2014 versus the first quarter of 2013 consisted of the following:

a $136$261 million increase in cash from overall higher partnership income—after adjusting our quarter-to-quarter $584$38 million increasedecrease in net income for the following fourtwo non-cash items: (i) a $320 million decrease from lower losses from both the sale and the remeasurement of our FTC Natural Gas Pipelines disposal group’s net assets to fair value; (ii) a $225 million decreaseincrease from the first quarter 2013 gain on the sale of our investments in Express (we reporteddeducted the proceeds receivedgain amount from this saleour net income within the operating activities section of our statement of cash flows)flows for the first quarter of 2013 and reported the proceeds received from this sale within the investing activities section); (iii) an $82and (ii) a $74 million increase due to higher depreciation, depletion and amortizationDD&A expenses (including amortization of excess cost of equity investments); and (iv) a $15 million increase related to a non-cash legal expense recorded. The period-to-period change in partnership income in the first quarter of 2013, associated with a certain environmental matter related to our West Coast terminal operations.
The quarter-to-quarter change in partnership income in 20132014 versus 2012 is discussed above in “—Results of Operations” (including all of the certain items disclosed in the associated table footnotes). The sale and

48


remeasurement of our FTC Natural Gas Pipelines disposal group and the sale of our investments in Express are all discussed further in Note 2 Acquisitions and Divestitures—Divestitures” to our consolidated financial statements included elsewhere in this report; and
a combined $48 million decrease in cash related to net changes in working capital items, non-current assets and liabilities, and other non-cash income and expense items. The overall decrease related primarily to the following four items: (i) a $91 million decrease in cash due to unfavorable changes in the collection and payment of trade and related party receivables and payables; (ii) a $71 million decrease in cash from net changes in cash book overdrafts, resulting from timing differences on checks issued but not yet presented for payment; (iii) a $64 million increase in cash due to lower expenditures for inventories, primarily due to higher payments made in the first quarter of 2012 for short-term liquids transmix inventories; and (iv) a $53 million increase in cash due to favorable changes in current income tax liabilities, due mainly to incremental income tax liabilities related to our sale of Express that have not yet been paid.
Investing Activities

Net cash used in investing activities was$1,171 million for the three month period ended March 31, 2013, compared to $373 million in the comparable 2012 period. The overall$798 million (214%) decrease in cash from investing activities primarily consisted of the following:

a $988 million decrease from our cash outlay as partial payment for the drop-down asset group in March 2013 as describedis discussed above in “—Capital Requirements for Recent Drop-Down Transaction;”Results of Operations” (including all of the certain items disclosed in the associated table footnotes); and
a $199$67 million decreaseincrease in cash due tofrom the combined net activity of our equity method investees and the net cash changes in operating assets and liabilities. The overall increase in cash was driven by higher capital expenditures, as described abovecash inflows from favorable changes in “—Capital Expenditures;”trade and related party accounts payables, and largely offset by, among other things, lower cash inflows from unfavorable changes in accrued tax liabilities.


54


Investing Activities

The overall $630 million (54%) quarter-to-quarterincrease in cash used in our investing activities in the first quarter of 2014 versus the first quarter of 2013 was primarily due to the following:
a $403$403 million increase from theof net proceeds we received in Marchthe first quarter of 2013 from the sale of our investments in the Express pipeline system.
Financing Activities
Net cash provided by financing activities amounted to $638 million for the three months ended March 31, 2013. In the comparable prior year period, we used $210 million in cash from financing activities. The $848 million (404%) overall increase in cash from the comparable 2012 period was mainly due to the following:
a $629 million increase in cash from overall debt financing activities—which include our issuancessystem; and payments of debt and our debt issuance costs. This increase in cash was primarily due to (i) a combined $447 million increase due to higher net issuances of our senior notes (in the first quarter of 2013, we generated proceeds of $991 million from the issuance of senior notes, and in the first quarter of 2012, we generated net cash proceeds of $544 million from both issuing and repaying senior notes); (ii) a $261 million increase due to lower short-term net repayments on borrowings made under our commercial paper program; and (iii) a $78 million decrease related to the net repayment of all of the outstanding borrowings under the midstream assets’ bank credit facility that we assumed on our March 1, 2013 acquisition date;
a$257 million increase in cash used due to higher capital expenditures in the first quarter of 2014, as described above in “—Capital Expenditures.”

For more information about our asset acquisitions during the first three months of 2014 and 2013, including our APT acquisition, see Note 2 “Acquisitions and Divestitures—Acquisitions” to our consolidated financial statements.
Financing Activities
The overall $42 million (7%) quarter-to-quarter increase in cash from all of our financing activities in the first quarter of 2014 versus the first quarter of 2013 was primarily attributable to the following:
a $261$240 million increase in cash due to higher partnership equity issuances. This increase reflects the $385combined $625 million we received, after commissions and underwriting expenses, from the sales ofissuing additional common units inand i-units during the first three monthsquarter of 20132014 (discussed in Note 4 “Partners’ Capital—Equity Issuances” to our consolidated financial statements included elsewhere in this report)statements), versus the $124$385 million we received from the sales of additional common units in the first quarter of 2013 (on February 26, 2013, we issued, in a year ago;
public offering, 4,600,000 of our common units at a $63 million increase in cash due to higher net contributions from noncontrolling interests, chiefly due to the $59 millionprice of contributions we received from our Battleground Oil Specialty Terminal Company LLC (BOSTCO) partners in the first quarter of 2013;$86.35 per unit, less commissions and underwriting expenses); and
a $140$165 million decrease in cash due to higher partnership distributions. Distributions to all partners, consisting of our common and Class B unitholders, our general partner and our noncontrolling interests, totaled $730895 million in

49


the first quarter of 2013. In the comparable quarter of 2012, we distributed $590 million to our partners. the first quarter of 2014, compared to $730 million in the first quarter of 2013. The increase in distributions was due to increases in the per unit cash distribution paid, the number of outstanding units, and the resulting increase in our general partner incentive distributions. Further information regarding our distributions is discussed following in “—Partnership Distributions.”

Partnership Distributions

Our partnership agreement requires that we distribute 100% of “Available Cash,” as defined in our partnership agreement, to our partners within 45 days following the end of each calendar quarter. Our 20122013 Form 10-K contains additional information concerning our partnership distributions, including the definition of “Available Cash,” the manner in which our total distributions are divided between our general partner and our limited partners, and the form of distributions to all of our partners, including our noncontrolling interests. For further information about the partnership distributions we paid in the first quarters of 20132014 and 20122013 (for the fourth quarterly periods of 20122013 and 2011,2012, respectively), see Note 4 “Partners’ Capital—Income Allocation and DeclaredPartnership Distributions” to our consolidated financial statements included elsewhere in this report.statements.

Furthermore, onOn April 17, 2013,16, 2014, we declared a cash distribution of $1.30$1.38 per unit for the first quarter of 2013 (an annualized rate of $5.20 per unit). This distribution is 8% higher than2014 compared to the $1.20$1.30 per unit distribution we made for the first quarter of 2012. Our2013. Based on (i) our declared distribution; (ii) the number of units outstanding; and (iii) our general partner’s agreement to forgo a combined$33 million of its incentive cash distribution in conjunction with both our May 2013 Copano acquisition and our January 2014 APT acquisition, our declared distribution for the first quarter of 20132014 of $1.30$1.38 per unit will result in an incentive distribution to our general partner of $398 million (including the effect of a waived incentive distribution amount of $4449 million related to our July 2011 KinderHawk acquisition).
Comparatively, our distribution of $1.20$1.30 per unit paid on May 15, 20122013 for the first quarter of 20122013 resulted in an incentive distribution payment to our general partner in the amount of $319$398 million (and included the effect of a waived incentive distribution amount of $64 million related to our July 2011 KinderHawk acquisition). The increased incentive distribution to our general partner for the first quarter of 20132014 over the incentive distribution for the first quarter of 20122013 reflects the increase in the distribution per unit as well as the issuance of additional units. For additional information about our first quarter 20132014 cash distribution, see Note 4 “Partners’ Capital—Subsequent Events”Event” to our consolidated financial statements included elsewhere in this report.statements. For additional information about our 20122013 partnership distributions, see Note 16 Litigation, Environmental10 “Partners’ Capital—Income Allocation and Other Contingencies”Declared Distributions” and Note 17 Regulatory Matters”11 “Related Party Transactions—Partnership Interests and Distributions” to our consolidated financial statements included in our 20122013 Form 10-K.

Currently, we expect to declare cash distributions
55


Although the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil and natural gas liquids,NGL, and while we hedge the majority of our crude oil production, we do have exposure on our unhedged volumes, the majority of which are natural gas liquidsNGL volumes.  Our 20132014 budget assumes an average West Texas Intermediate (WTI)WTI crude oil price of approximately $91.68$96.15 per barrel (with some minor adjustments for timing, quality and location differences) in 2013,2014, and based on the actual prices we have received through the date of this report and the forward price curve for WTI (adjusted for the same factors used in our 20132014 budget), we currently expect the average price of WTI crude oil will be approximately $93.8996.62 per barrel in 2013.2014. For 2013,2014, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $6$7 million on a full year basis (or approximately 0.1%0.125% of our combined business segments’ anticipated earnings before depreciation, depletion and amortizationEBDA expenses).  This sensitivity to the average WTI price is very similar to what we experienced in 2012.2013.
Off Balance Sheet Arrangements
There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2012 in our 2012 Form 10-K.

Recent Accounting Pronouncements

50


Please refer to Note 11 “Recent Accounting Pronouncements” to our consolidated financial statements included elsewhere in this report for information concerning recent accounting pronouncements.

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

See Part I, Item 1A “Risk Factors” and Part II, Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Information Regarding Forward-Looking Statements” of our 2012 Form 10-K for a more detailed description of factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in our 2012 Form 10-K. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update any forward-looking statements to reflect future events or developments after the date of this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 20122013, in Item 7A ofin our 20122013 Form 10-K. For more information on our risk management activities, see Note 5 “Risk Management” to our consolidated financial statements included elsewhere in this report.

Item 4. Controls and Procedures.
As of March 31, 20132014, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended March 31, 20132014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


5156


PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies,” which is incorporated in this item by reference.

Item 1A. Risk Factors.
There have been no material changes in or additions to the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 20122013 Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
On March 1, 2013, we paid to KMI $988 million in cash, issued 1,249,452 common units, and assumed $557 million in debt for the acquisition of certain natural gas pipeline assets. We valued the common units at $108 million, determining the units’ value based on the $86.72 closing market price of a common unit on the New York Stock Exchange on the March 1, 2013 issuance date. The units were issued to KMI pursuant to Section 4(2) of the Securities Act of 1933.None.
Item 3. Defaults Upon Senior Securities.
None.

Item 4. Mine Safety Disclosures
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in exhibit 95 to this quarterly report.

Item 5. Other Information.
None.


57


Item 6. Exhibits.


52


4.1*2.1 —Agreement and Plan of Merger, dated as of January 29, 2013, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan, G.P., Inc, Javelina Merger Sub LLC and Copano Energy, L.L.C. (filed as Exhibit 2.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on February 4, 2013 and incorporated herein by reference).
3.1 —
Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P.

4.1 Certificate of the Vice President, Finance and Chief Financial OfficerInvestor Relations and the Vice President General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the terms of the 3.50% Senior Notes due September 1, 2023,2021 and the 5.00%5.50% Senior Notes due March 1, 2043.2044.

4.24.2 —
Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K (17 CFR 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.
12*10.1 —
Voting Agreement, dated as of January 29, 2013, by and among Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Copano Energy, L.L.C. and TPG Copenhagen, L.P. (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on February 4, 2013 and incorporated herein by reference).
11 Statement re: computation of per share earnings.
 12 —Statement re: computation of ratio of earnings to fixed charges.
31.1 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 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 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.

32.232.2 —
Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

9595 —
Mine Safety Disclosures.
101101 —
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three months ended March 31, 20132014 and 2012;2013; (ii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 20132014 and 2012;2013; (iii) our Consolidated Balance Sheets as of March 31, 20132014 and December 31, 2012;2013; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, 20132014 and 2012;2013; (v) our Consolidated Statements of Partners’ Capital for the three months ended March 31, 2014 and (v)2013; and (vi) the notes to our Consolidated Financial Statements.

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


5358


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

 KINDER MORGAN ENERGY PARTNERS, L.P.
 Registrant (a Delaware limited partnership)
Limited Partnership)
  
By:
By: KINDER MORGAN G.P., INC.,
Its sole General Partner
  its sole General Partner
 
By:
KINDER MORGAN MANAGEMENT, LLC,
the Delegate of Kinder Morgan G.P., Inc.
Date: April 29, 2013By:/s/ Kimberly A. Dang
 
 By: /s/ KIMBERLY A. DANG
 
Kimberly A. Dang,
Vice President and Chief Financial Officer
(principal financial and accounting officer)

Date: April 29, 2014




5459