UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
(Mark One)
   
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended JuneSeptember 30, 2011
OR
   
o 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 1-14365
El Paso Corporation
(Exact Name of Registrant as Specified in Its Charter)
   
Delaware
76-0568816
(State or Other Jurisdiction of
(I.R.S. Employer
Incorporation or Organization) 76-0568816
(I.R.S. Employer
Identification No.)
   
El Paso Building
77002
1001 Louisiana Street
(Zip Code)
Houston, Texas
(Address of Principal Executive Offices) 77002
(Zip Code)
Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
     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. Yesþ Noo
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ Noo
     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 filerþ Accelerated filero Non-accelerated filero(Do not check if a smaller reporting company) Smaller reporting companyo
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
     Common stock, par value $3 per share. Shares outstanding on August 2,November 1, 2011: 770,247,634771,195,525
 
 

 

 

EL PASO CORPORATION
TABLE OF CONTENTS
     
Caption Page 
PART I — FINANCIAL INFORMATION
    
Item 1. Financial Statements
  1 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
  2628 
Item 3. Quantitative and Qualitative Disclosures About Market Risk
  4346 
Item 4. Controls and Procedures
  4447
 
PART II — OTHER INFORMATION
    
Item 1. Legal Proceedings
  4548 
Item 1A. Risk Factors
  4548 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
  4651 
Item 3. Defaults Upon Senior Securities
  4651 
Item 4. (Removed and Reserved)
  4751 
Item 5. Other Information
  4751 
Item 6. Exhibits
  4751 
Signatures
  4852
 
 EX-12
 EX-31.A
 EX-31.B
 EX-32.A
 EX-32.B
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT
Below is a list of terms that are common to our industry and used throughout this document:
   
/d = per day
Bbl = barrels
BBtu = billion British thermal units
Bcf= billion cubic feet
GW = gigawatts
GWh = gigawatt hours
LNG = liquefied natural gas
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas equivalents
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas equivalents
NGL = natural gas liquids
TBtu = trillion British thermal units
     When we refer to oil and natural gas in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
     When we refer to “us”, “we”, “our”, “ours”, “the Company” or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

 

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
Operating revenues $1,236 $1,018 $2,225 $2,419  $1,403 $1,213 $3,628 $3,632 
                  
Operating expenses  
Cost of products and services 44 53 91 106  44 57 135 163 
Operation and maintenance 323 285 628 586  366 327 994 911 
Loss on deconsolidation of subsidiary (Note 15) 600 — 600 — 
Ceiling test charges 152 14 152 16 
Depreciation, depletion and amortization 262 242 516 460  299 239 815 699 
Taxes, other than income taxes 78 54 154 123  63 58 217 181 
                  
 707 634 1,389 1,275  1,524 695 2,913 1,970 
                  
  
Operating income 529 384 836 1,144 
Operating income (loss)  (121) 518 715 1,662 
Earnings from unconsolidated affiliates 32 111 62 139  36 28 98 167 
Loss on debt extinguishment  (27) —  (68) —   (101)  (104)  (169)  (104)
Other income, net 82 57 181 117  5 71 186 188 
Interest and debt expense  (239)  (284)  (479)  (527)  (242)  (255)  (721)  (782)
                  
Income before income taxes 377 268 532 873 
Income tax expense 38 82 57 268 
Income (loss) before income taxes  (423) 258 109 1,131 
Income tax expense (benefit)  (130) 75  (73) 343 
                  
Net income 339 186 475 605 
Net income (loss)  (293) 183 182 788 
Net income attributable to noncontrolling interests  (77)  (29)  (151)  (60)  (75)  (41)  (226)  (101)
                  
Net income attributable to El Paso Corporation 262 157 324 545 
Net income (loss) attributable to El Paso Corporation  (368) 142  (44) 687 
 
Preferred stock dividends of El Paso Corporation — 10 — 19  — 9 — 28 
                  
Net income attributable to El Paso Corporation’s common stockholders $262 $147 $324 $526 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(368) $133 $(44) $659 
                  
Basic earnings per common share  
Net income attributable to El Paso Corporation’s common stockholders $0.34 $0.21 $0.44 $0.75 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(0.48) $0.19 $(0.06) $0.95 
                  
Diluted earnings per common share  
Net income attributable to El Paso Corporation’s common stockholders $0.34 $0.21 $0.42 $0.72 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(0.48) $0.19 $(0.06) $0.90 
                  
  
Dividends declared per El Paso Corporation’s common share $0.01 $0.01 $0.02 $0.02  $0.01 $0.01 $0.03 $0.03 
                  
See accompanying notes.

1

EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
(Unaudited)
                 
  Quarters Ended  Six Months Ended 
  June 30,  June 30, 
  2011  2010  2011  2010 
Net income $339  $186  $475  $605 
             
Pension and postretirement obligations:                
Reclassification of net actuarial losses during period (net of income taxes of $7 and $14 in 2011 and $6 and $12 in 2010)  15   11   31   24 
Cash flow hedging activities:                
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $15 and $13 in 2011 and $23 and $25 in 2010)  (27)  (37)  (24)  (40)
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $1 and $2 in 2011 and $1 and $2 in 2010)  4   2   7   4 
             
Other comprehensive income (loss)  (8)  (24)  14   (12)
             
Comprehensive income  331   162   489   593 
Comprehensive income attributable to noncontrolling interests  (77)  (29)  (151)  (60)
             
Comprehensive income attributable to El Paso Corporation $254  $133  $338  $533 
             
                 
  Quarters Ended  Nine Months Ended 
  September 30,  September 30, 
  2011  2010  2011  2010 
Net income (loss) $(293) $183  $182  $788 
             
Pension and postretirement obligations:                
Unrealized actuarial gains on postretirement benefit plans (net of income taxes of $6 and $6 in 2011)  13   —   13   — 
Reclassification of net actuarial losses during period (net of income taxes of $8 and $22 in 2011 and $6 and $18 in 2010)  15   11   46   35 
Cash flow hedging activities:                
Unrealized mark-to-market losses arising during period (net of income taxes of $27 and $40 in 2011 and $20 and $45 in 2010)  (42)  (31)  (66)  (71)
Recognition of loss associated with interest rate swaps upon deconsolidation of subsidiary (net of income taxes of $46 and $46 in 2011)  79   —   79   — 
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $6 and $8 in 2011 and $1 and $3 in 2010)  7   1   14   5 
             
Other comprehensive income (loss)  72   (19)  86   (31)
             
Comprehensive income (loss)  (221)  164   268   757 
Comprehensive loss attributable to noncontrolling interests  (79)  (41)  (230)  (101)
             
Comprehensive income (loss) attributable to El Paso Corporation $(300) $123  $38  $656 
             
See accompanying notes.

2

EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2011 2010  2011 2010 
ASSETS  
Current assets  
Cash and cash equivalents (include $38 in 2011 and $31 in 2010 held by variable interest entities) $260 $347 
Cash and cash equivalents (includes $31 in 2010 held by variable interest entities) $390 $347 
Accounts and notes receivable  
Customer, net of allowance of $5 in 2011 and $4 in 2010 329 333 
Customer, net of allowance of $4 in both 2011 and 2010 322 333 
Affiliates 6 7  8 7 
Other 183 160  165 160 
Materials and supplies 180 169  167 169 
Assets from price risk management activities 204 265  314 265 
Deferred income taxes 284 165  107 165 
Other 106 106  154 106 
          
Total current assets 1,552 1,552  1,627 1,552 
          
  
Property, plant and equipment, at cost  
Pipelines (include $4,029 in 2011 and $3,232 in 2010 held by variable interest entities) 23,378 22,385 
Pipelines (includes $3,232 in 2010 held by variable interest entities) 19,771 22,385 
Oil and natural gas properties, at full cost 22,331 21,692  21,556 21,692 
Other 477 416  513 416 
          
 46,186 44,493  41,840 44,493 
Less accumulated depreciation, depletion and amortization 23,617 23,421  23,102 23,421 
          
Total property, plant and equipment, net 22,569 21,072  18,738 21,072 
          
  
Other long-term assets  
Investments in unconsolidated affiliates 1,689 1,673  2,756 1,673 
Assets from price risk management activities 36 61  51 61 
Other 1,112 912  906 912 
          
 2,837 2,646  3,713 2,646 
          
Total assets $26,958 $25,270  $24,078 $25,270 
          
See accompanying notes.

3

EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
(Unaudited)
                
 June 30, December 31,  September 30, December 31, 
 2011 2010  2011 2010 
LIABILITIES AND EQUITY  
Current liabilities  
Accounts payable  
Trade $474 $610  $384 $610 
Affiliates 11 9  11 9 
Other 423 386  447 386 
Short-term financing obligations, including current maturities 618 489  350 489 
Liabilities from price risk management activities 194 176  152 176 
Asset retirement obligations 65 63  62 63 
Accrued interest 203 202  224 202 
Other 579 630  612 630 
          
Total current liabilities 2,567 2,565  2,242 2,565 
          
  
Long-term financing obligations, less current maturities 13,594 13,517  12,531 13,517 
          
  
Other long-term liabilities  
Liabilities from price risk management activities 387 397  271 397 
Deferred income taxes 764 568  527 568 
Other 1,436 1,461  1,352 1,461 
          
 2,587 2,426  2,150 2,426 
          
  
Commitments and contingencies (Note 8) 
Commitments and contingencies (Note 10) 
Preferred stock of subsidiaries 763 698  — 698 
          
  
Equity  
El Paso Corporation stockholders’ equity:  
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares of 4.99% convertible perpetual stock as of December 31, 2010; stated at liquidation value — 750  — 750 
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 785,159,805 shares in 2011 and 719,743,724 shares in 2010 2,355 2,159 
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 785,546,406 shares in 2011 and 719,743,724 shares in 2010 2,357 2,159 
Additional paid-in capital 5,444 4,484  5,449 4,484 
Accumulated deficit  (2,110)  (2,434)  (2,478)  (2,434)
Accumulated other comprehensive loss  (737)  (751)  (669)  (751)
Treasury stock (at cost); 15,053,056 shares in 2011 and 15,492,605 shares in 2010  (282)  (291)
Treasury stock (at cost); 15,063,780 shares in 2011 and 15,492,605 shares in 2010  (283)  (291)
          
Total El Paso Corporation stockholders’ equity 4,670 3,917  4,376 3,917 
Noncontrolling interests 2,777 2,147  2,779 2,147 
          
Total equity 7,447 6,064  7,155 6,064 
          
Total liabilities and equity $26,958 $25,270  $24,078 $25,270 
          
See accompanying notes.

4

EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
                
 Six Months Ended  Nine Months Ended 
 June 30,  September 30, 
 2011 2010  2011 2010 
Cash flows from operating activities  
Net income $475 $605  $182 $788 
Adjustments to reconcile net income to net cash from operating activities 
Adjustments to reconcile net income to net cash from operating activities: 
Depreciation, depletion and amortization 516 460  815 699 
Deferred income tax expense 73 270 
Ceiling test charges 152 16 
Loss on deconsolidation of subsidiary (Note 15) 600 — 
Deferred income tax expense (benefit)  (28) 339 
Earnings from unconsolidated affiliates, adjusted for cash distributions  (31)  (104)  (50)  (115)
Loss on debt extinguishment 68 —  169 104 
Other non-cash income items  (96)  (22)  (72)  (34)
Asset and liability changes  (9)  (315)  (151)  (385)
          
Net cash provided by operating activities 996 894  1,617 1,412 
          
  
Cash flows from investing activities  
Capital expenditures  (2,016)  (1,502)  (2,989)  (2,641)
Cash paid for acquisitions, net of cash acquired  (2)  (25)
Net proceeds from the sale of assets and investments 29 293  592 332 
Increase in notes receivable  (112)  (16)  (115)  (23)
Other — 27   (69) 37 
          
Net cash used in investing activities  (2,099)  (1,198)  (2,583)  (2,320)
          
  
Cash flows from financing activities  
Net proceeds from issuance of long-term debt 2,976 965  5,168 1,399 
Payments to retire long-term debt and other financing obligations  (2,861)  (1,060)  (5,001)  (1,273)
Net proceeds from issuance of noncontrolling interests 948 549 
Net proceeds from issuance of noncontrolling interests (Note 12) 948 956 
Net proceeds from issuance of preferred stock of subsidiary 30 120 
Dividends paid  (31)  (49)
Distributions to noncontrolling interest holders  (86)  (39)  (143)  (64)
Net proceeds from issuance of preferred stock of subsidiary 30 — 
Distributions to holders of preferred stock of subsidiary  (10)  (10)  (10)  (15)
Dividends paid  (23)  (33)
Proceeds from stock option exercises 43 4  48 6 
Other  (1) —  — 2 
          
Net cash provided by financing activities 1,016 376  1,009 1,082 
          
  
Change in cash and cash equivalents  (87) 72  43 174 
Cash and cash equivalents  
Beginning of period 347 635  347 635 
          
End of period $260 $707  $390 $809 
          
See accompanying notes.

5

EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
(Unaudited)
                
 Six Months Ended  Nine Months Ended 
 June 30,  September 30, 
 2011 2010  2011 2010 
El Paso Corporation stockholders’ equity:  
Preferred stock:  
Balance at beginning of period $750 $750  $750 $750 
Conversion of preferred stock  (750) —   (750) — 
          
Balance at end of period — 750  — 750 
          
Common stock:  
Balance at beginning of period 2,159 2,148  2,159 2,148 
Conversion of preferred stock 174 —  174 — 
Other, net 22 10  24 11 
          
Balance at end of period 2,355 2,158  2,357 2,159 
          
Additional paid-in capital:  
Balance at beginning of period 4,484 4,501  4,484 4,501 
Conversion of preferred stock 576 —  576 — 
Dividends  (14)  (33)  (22)  (49)
Issuances of noncontrolling interests (Note 10) 338 — 
Issuances of noncontrolling interests (Note 12) 338 — 
Other, including stock-based compensation 60 19  73 32 
          
Balance at end of period 5,444 4,487  5,449 4,484 
          
Accumulated deficit:  
Balance at beginning of period  (2,434)  (3,192)  (2,434)  (3,192)
Net income attributable to El Paso Corporation 324 545 
Net income (loss) attributable to El Paso Corporation  (44) 687 
          
Balance at end of period  (2,110)  (2,647)  (2,478)  (2,505)
          
Accumulated other comprehensive income (loss):  
Balance at beginning of period  (751)  (718)  (751)  (718)
Other comprehensive income (loss) 14  (12)
Other comprehensive income (loss) attributable to noncontrolling interests 82  (31)
          
Balance at end of period  (737)  (730)  (669)  (749)
          
Treasury stock, at cost:  
Balance at beginning of period  (291)  (283)  (291)  (283)
Stock-based and other compensation 9  (7) 8  (7)
          
Balance at end of period  (282)  (290)  (283)  (290)
          
Total El Paso Corporation stockholders’ equity at end of period 4,670 3,728  4,376 3,849 
          
  
Noncontrolling interests:  
Balance at beginning of period 2,147 785  2,147 785 
Issuances of noncontrolling interests (Note 10) 610 549 
Issuance of noncontrolling interests (Note 12) 610 956 
Distributions to noncontrolling interests  (86)  (39)  (143)  (64)
Net income attributable to noncontrolling interests (Note 10) 106 50 
Net income attributable to noncontrolling interests (Note 12) 161 75 
Other comprehensive income attributable to noncontrolling interests 4 — 
          
Balance at end of period 2,777 1,345  2,779 1,752 
          
Total equity at end of period $7,447 $5,073  $7,155 $5,601 
          
See accompanying notes.

6

EL PASO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of Presentation and Significant Accounting Policies
Basis of Presentation
     We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). As an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles (GAAP) and should be read along with our 2010 Annual Report on Form 10-K. The financial statements as of JuneSeptember 30, 2011, and for the quarters and sixnine months ended JuneSeptember 30, 2011 and 2010, are unaudited. The condensed consolidated balance sheet as of December 31, 2010 was derived from the audited balance sheet filed in our 2010 Annual Report on Form 10-K. In our opinion, we have made adjustments, all of which are of a normal, recurring nature, to fairly present our interim period results. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income or stockholders’ equity. Additionally, our statement of cash flows for the sixnine months ended JuneSeptember 30, 2010 reflects a decrease in both net cash provided by operating activities and net cash used in investing activities related to the timing of certain capital expenditures which was considered immaterial to our 2010 consolidated financial statements. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of our operating results for the entire year. Our disclosures in this Form 10-Q are an update to those provided in our 2010 Annual Report on Form 10-K.
     On May 24,October 16, 2011, we announced a definitive agreement with Kinder Morgan, Inc. (KMI) whereby KMI will acquire El Paso Corporation (El Paso) in a transaction that values El Paso at approximately $38 billion, including the assumption of debt. The transaction has been approved by each of our Boardand KMI’s board of Directors had granted initialdirectors. The completion of the transaction is subject to satisfaction or waiver of certain closing conditions including, among others, customary regulatory approvals, approval of the transaction by our stockholders and approval of the issuance of KMI stock and warrants by KMI’s stockholders. A voting agreement has been executed by certain stockholders of KMI, holding approximately 75% of the voting power of KMI, in which such stockholders have agreed to vote in favor of the merger and issuance of KMI stock and warrants. The completion of the merger will constitute a planchange of control for El Paso that may trigger change in control provisions in certain agreements (e.g., debt) to separatewhich we are a party. KMI has announced that they intend to sell our exploration and production assets and as such, we will no longer pursue the Company into two publicly traded businesses by the end of 2011. The plan calls for a tax-free spin-off of our exploration and production business and related activities into a new publicly traded company separate fromcompany.
     Upon the merger, El Paso Corporation (EPC). The planned separation isshareholders will receive a combination of Class P shares of common stock of KMI, common stock purchase warrants of KMI and cash. Each share of El Paso common stock (excluding any shares held by KMI or its subsidiaries or by El Paso and dissenting shares in accordance with Delaware law), will, at the effective time of the merger, be converted into the right to receive, at the election of the holder but subject to market, regulatory, tax and final approval by our Board of Directors and other customary conditions. Untilpro-ration with respect to the separation is complete, the results of operations, financial positionstock and cash flowsportion such that approximately 57% of our explorationthe aggregate merger consideration (excluding the warrants) is paid in cash and production businessapproximately 43% (excluding the warrants) is paid in Class P common stock of KMI, par value $0.01 per share (the “KMI Class P Common Stock”): (i) 0.9635 of a share of KMI Class P Common Stock and 0.640 of a common stock purchase warrant of KMI (a “KMI Warrant”), (ii) $25.91 in cash without interest and 0.640 of a KMI Warrant or (iii) 0.4187 of a share of KMI Class P Common Stock, $14.65 in cash without interest and 0.640 of a KMI Warrant. Each KMI Warrant will be reported as continuing operations.entitle its holder to purchase one share of KMI Class P Common Stock at an exercise price of $40.00 per share, subject to certain adjustments, at any time during the five-year period following the closing of the merger.
Significant Accounting Policies
     There were no changes in the significant accounting policies described in our 2010 Annual Report on Form 10-K and no significant accounting pronouncements issued but not yet adopted as of JuneSeptember 30, 2011.

7

2. Divestitures
     During 2011, we sold non-core oil and natural gas properties located in our Central, Western and Southern divisions in several transactions from which we received proceeds that totaled approximately $570 million. During 2010, we also sold non-core natural gas producing properties located in our Southern division for approximately $22 million. No gain or loss was recorded on the second quartersale of the oil and gas properties in either year. Additionally, during the nine months ended September 30, 2010 we completed the sale of certain of our interests in Mexican pipeline and compression assets for approximately $300 million and recorded a pretax gain of approximately $80 million in earnings from unconsolidated affiliates. In July
3. Ceiling Test Charges
     We are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. During the quarters and nine months ended September 30, 2011 and 2010, we sold oilrecorded the following ceiling test charges:
                 
  Quarters Ended September 30,  Nine Months Ended September 30, 
  2011  2010  2011  2010 
      (In millions)     
Full cost pool:                
Brazil $152  $—  $152  $— 
Egypt  —   14   —   16 
             
Total $152  $14  $152  $16 
             
     Our Brazilian charge was driven, in part, by the release of certain unevaluated costs into the Brazilian full cost pool primarily as a result of the recent denial of a necessary environmental permit. See Note 8 for a further discussion. We may incur additional ceiling test charges in Brazil in the future depending on the value of our proved reserves, which are subject to change as a result of factors such as prices, costs and natural gas properties locatedwell performance. Additionally, we may incur ceiling test charges in Alabama for approximately $104 million.Egypt depending on the results of our activities in that country.

7

3.4. Other Income, Net
     The following are the components of other income and other expense for the quarters and sixnine months ended JuneSeptember 30:
                                
 Quarters Ended June 30, Six Months Ended June 30,  Quarters Ended September 30, Nine Months Ended September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Other Income, Net              
Allowance for equity funds used during construction $74 $51 $171 $101  $16 $55 $187 $156 
Other 8 6 10 16   (11) 16  (1) 32 
                  
Total $82 $57 $181 $117  $5 $71 $186 $188 
                  
     Allowance for Equity Funds Used During Construction.As allowed by the Federal Energy Regulatory Commission (FERC), we capitalize a pre-tax carrying cost on equity funds related to the construction of long-lived assets in our FERC regulated business and reflect this amount as an increase in the cost of the asset on our balance sheet. We calculate this amount using the most recent FERC approved equity rate of return. These amounts are recovered over the depreciable lives of the long-lived assets to which they relate.
4.5. Income Taxes
     Income taxes for the quarters and sixnine months ended JuneSeptember 30 were as follows:
                                
 Quarters Ended June 30, Six Months Ended June 30,  Quarters Ended September 30, Nine Months Ended September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions, except rates)  (In millions, except rates) 
Income tax expense $38 $82 $57 $268 
Income tax expense (benefit) $(130) $75 $(73) $343 
Effective tax rate  10%  31%  11%  31%  31%  29%  (67)%  30%

8

     Effective Tax Rate.We compute interim period income taxes by applying an anticipated annual effective tax rate to our year-to-date income or loss, except for significant unusual or infrequently occurring items, which are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period of enactment. Our effective tax rate is affectedprimarily impacted by items such as income attributable to nontaxable noncontrolling interests, dividend exclusions on earnings from unconsolidated affiliates where we anticipate receiving dividends, the effect of state income taxes (net of federal income tax effects) and the effect of foreign income which can be taxed at different rates.
     For the quarter and six months ended JuneSeptember 30, 2011, our effective tax rate was significantly lower than the statutory rate primarily due to the benefit to our anticipated annual effective tax rate ofimpacted by income attributable to nontaxable noncontrolling interests and a Brazilian ceiling test charge without a corresponding U.S. or Brazilian tax benefit (deferred tax benefits related to the Brazilian ceiling test charge were offset by an equal valuation allowance).
     For the nine months ended September 30, 2011, our income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of El Paso Pipeline Partners, L.P. (EPB), dividend exclusions on earnings from unconsolidated affiliates where we anticipate receiving dividends35 percent for the following reasons:
     
  September 30, 2011 
  (In millions, except rates) 
Income taxes at the statutory federal rate of 35% $38 
Increase (decrease)    
Income attributable to nontaxable noncontrolling interests  (92)
Foreign income taxed at different rates  45 
State income taxes, net of federal income tax effect  (31)
Earnings from unconsolidated affiliates where we anticipate receiving dividends  (29)
Other  (4)
    
Income tax expense (benefit) $(73)
    
Effective tax rate  (67)%
    
Foreign income taxed at different rates in the table above includes $53 million related to the impact of the Brazilian ceiling test charge without a corresponding U.S. or Brazilian tax benefit (deferred tax benefits related to the Brazilian ceiling test charge were offset by an equal valuation allowance) and the favorable resolution of certain tax matters.matters in the first half of 2011.State income taxes, net of federal income tax effect in the table above includes the state tax benefit associated with the third quarter non-cash loss on the deconsolidation of Ruby (see Note 15) and the favorable resolution of certain tax matters in the first half of 2011.
     In the fourth quarter of 2011, we will record a significant deferred state tax benefit of approximately $65 million due to an expected reduction to state tax rates as a result of a conversion of a subsidiary to a limited liability company on October 1, 2011.
     For the quarter and sixnine months ended JuneSeptember 30, 2010, our effective tax rate was impacted by income attributable to nontaxable noncontrolling interests and the liquidation of certain foreign entities. Also impacting our effective tax rate for the nine months ended September 30, 2010 was the sale of certain of our interests in Mexican pipeline and compression assets and income attributable to nontaxable noncontrolling interests.assets. Partially offsetting these items was $18 million of additional deferred income tax expense recorded in the first quarter of 2010 from healthcare legislation enacted in March 2010.
Unrecognized Tax Benefits.We believe it is reasonably possible that the total amount of unrecognized tax benefits (including interest and penalty) could decrease by as much as $70 million over the next 12 months as a result of the anticipated favorable resolution of certain tax matters.

89

5.6. Earnings Per Share
     Basic and diluted earnings per common share were as follows for the quarters and sixnine months ended JuneSeptember 30:
Quarters Ended JuneSeptember 30,
                                
 2011 2010  2011 2010 
 Basic Diluted Basic Diluted  Basic Diluted Basic Diluted 
 (In millions, except per share amounts)  (In millions, except per share amounts) 
Net income attributable to El Paso Corporation $262 $262 $157 $157 
Net income (loss) attributable to El Paso Corporation $(368) $(368) $142 $142 
Preferred stock dividends of El Paso Corporation — —  (10) —  — —  (9) — 
Interest on trust preferred securities — 3 — — 
                  
Net income attributable to El Paso Corporation’s common stockholders $262 $265 $147 $157 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(368) $(368) $133 $142 
                  
  
Weighted average common shares outstanding 763 763 698 698  764 764 699 699 
Effect of dilutive securities:  
Options and restricted stock — 11 — 5  — — — 5 
Convertible preferred stock — — — 58  — — — 58 
Trust preferred securities — 8 — — 
                  
Weighted average common shares outstanding and dilutive securities 763 782 698 761  764 764 699 762 
                  
  
Basic and diluted earnings per common share: 
Net income attributable to El Paso Corporation’s common stockholders $0.34 $0.34 $0.21 $0.21 
Basic and diluted earnings (loss) per common share: 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(0.48) $(0.48) $0.19 $0.19 
                  

10

SixNine Months Ended JuneSeptember 30,
                                
 2011 2010  2011 2010 
 Basic Diluted Basic Diluted  Basic Diluted Basic Diluted 
 (In millions, except per share amounts)  (In millions, except per share amounts) 
Net income attributable to El Paso Corporation $324 $324 $545 $545 
Net income (loss) attributable to El Paso Corporation $(44) $(44) $687 $687 
Preferred stock dividends of El Paso Corporation — —  (19) —  — —  (28) — 
Interest on trust preferred securities — — — 5 
                  
Net income attributable to El Paso Corporation’s common stockholders $324 $324 $526 $550 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(44) $(44) $659 $687 
                  
  
Weighted average common shares outstanding 738 738 697 697  747 747 698 698 
Effect of dilutive securities:  
Options and restricted stock — 11 — 5  — — — 5 
Convertible preferred stock — 22 — 58  — — — 58 
Trust preferred securities — — — 8 
                  
Weighted average common shares outstanding and dilutive securities 738 771 697 768  747 747 698 761 
                  
  
Basic and diluted earnings per common share: 
Net income attributable to El Paso Corporation’s common stockholders $0.44 $0.42 $0.75 $0.72 
Basic and diluted earnings (loss) per common share: 
Net income (loss) attributable to El Paso Corporation’s common stockholders $(0.06) $(0.06) $0.95 $0.90 
                  
     We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income attributable to El Paso Corporation per common share is antidilutive. Our potentially dilutive securities consist of employee stock options, restricted stock, trust preferred securities and convertible preferred stock. In March 2011, we converted our preferred stock to common stock as further described in Note 10.12. For the quarters and sixnine months ended JuneSeptember 30, 2011, we incurred losses attributable to El Paso Corporation and, accordingly, excluded all potentially dilutive securities from the determination of diluted earnings per share. For the quarter and nine months ended September 30, 2010, certain of our employee stock options were antidilutive. Additionally, for the quarter ended June 30, 2010 and the six months ended June 30, 2011, our trust preferred securities were antidilutive.

911

6.7. Financial Instruments
     The following table reflects the carrying value and fair value of our financial instruments:
                                
 June 30, 2011 December 31, 2010  September 30, 2011 December 31, 2010 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 Amount Value Amount Value  Amount Value Amount Value 
 (In millions)  (In millions) 
Long-term financing obligations, including current maturities $14,212 $15,799 $14,006 $14,686  $12,881 $14,230 $14,006 $14,686 
Marketable securities in non-qualified compensation plans 21 21 20 20  20 20 20 20 
Commodity-based derivatives  (246)  (246)  (186)  (186)  (45)  (45)  (186)  (186)
Interest rate derivatives  (95)  (95)  (61)  (61)  (13)  (13)  (61)  (61)
Other  (12)  (12)  (11)  (11)  (11)  (11)  (11)  (11)
     As of JuneSeptember 30, 2011 and December 31, 2010, the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and short-term financing obligations represent fair value because of the short-term nature of these instruments. The carrying amounts of our restricted cash and noncurrent receivables approximate their fair value based on the nature of their interest rates and our assessment of the ability to recover these amounts. We estimated the fair value of our long-term financing obligations based on quoted market prices for the same or similar issues,issuances, including consideration of our credit risk related to those instruments.
     Our derivative financial instruments are further described in our 2010 Annual Report on Form 10-K and below:
 • Production-Related Commodity Based Derivatives.As of JuneSeptember 30, 2011 and December 31, 2010, we have production-related derivatives (oil and natural gas swaps, collars, basis swaps and option contracts) to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil and natural gas production on 17,38215,956 MBbl and 12,240 MBbl of oil and 200149 TBtu and 283 TBtu of natural gas. None of these contracts are designated as accounting hedges.
 • Other Commodity-Based Derivatives.As of JuneSeptember 30, 2011 and December 31, 2010, in our Marketing segment we have forwards, swaps and options contracts related to long-term natural gas and power. These contracts, the longest of which extends into 2019, include (i) obligations to sell natural gas to power plants ranging from 12,550 MMBtu/d to 95,000 MMBtu/d and (ii) an obligation to swap locational differences in power prices between three power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub on approximately 1,700 to 3,700 GWh, to provide annually approximately 1,700 GWh of power and approximately 71 GW of installed capacity in the PJM power pool. We have entered into contracts to economically mitigate our exposure to commodity price changes and locational price differences on substantially all of these natural gas and power volumes. None of these derivatives are designated as accounting hedges.
 • Interest Rate Derivatives.We have long-term debt with variable interest rates that exposes us to changes in market-based interest rates. As of JuneSeptember 30, 2011 and December 31, 2010, we had interest rate swaps that are designated as cash flow hedges that effectively convert the interest rate on approximately $0.2 billion and $1.3 billion of debt from a floating LIBOR interest rate to a fixed interest rate. ApproximatelyThe majority of the balance at December 31, 2010 related to interest rate swaps on $1.1 billion of the debt hedged as of June 30, 2011 relates to debt associated with our Ruby pipeline project thatdebt. These hedges began accruing interest on July 1,June 30, 2011 and have termination dates ranging from June 2013 to June 2017. These termination dates2017 which correspond to the estimated principal outstanding on the Ruby debt over the term of these swaps. In connection with the deconsolidation of Ruby, these interest rate swaps and the related accumulated other comprehensive loss are no longer reflected on our balance sheet. For a further discussion of our Ruby, financing, see Note 7.15.
     We also have long-term debt with fixed interest rates that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps designated as fair value hedges to protect the value of certain of these debt instruments by converting the fixed amounts of interest due under the debt agreements to variable interest payments. We record changes in the fair value of these derivatives in interest expense which is offset by changes in the fair value of the related hedged items. As of JuneSeptember 30, 2011 and December 31, 2010, these interest rate swaps converted the interest rate on approximately $162 million and $184 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18%.

1012

     Fair Value Measurement.We separate the fair values of our financial instruments into three 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. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument. During the quarter and sixnine months ended JuneSeptember 30, 2011, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified. Our marketable securities in non-qualified compensation plans and other are reflected at fair value on our balance sheets as other long-term assets, other current liabilities and other long-term liabilities. We net our derivative assets and liabilities for counterparties where we have a legal right of offset and classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. At JuneSeptember 30, 2011 and December 31, 2010, cash collateral held was not material. The following table presents the fair value of our financial instruments at JuneSeptember 30, 2011 and December 31, 2010 (in millions).
                                                                
 June 30, 2011 December 31, 2010  September 30, 2011 December 31, 2010 
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 
Assets
  
Commodity-based derivatives
  
Production-related oil and natural gas derivatives $— $285 $— $285 $— $373 $— $373  $— $379 $— $379 $— $373 $— $373 
Other natural gas derivatives — 116 16 132 — 139 18 157  — 74 16 90 — 139 18 157 
Power-related derivatives — — 23 23 — — 31 31  — — 16 16 — — 31 31 
                                  
Total commodity-based derivative assets — 401 39 440 — 512 49 561  — 453 32 485 — 512 49 561 
Interest rate derivatives designated as hedges
  
Fair value hedges — 5 — 5 — 8 — 8  — 3 — 3 — 8 — 8 
Impact of master netting arrangements
 —  (194)  (11)  (205) —  (229)  (14)  (243) —  (113)  (10)  (123) —  (229)  (14)  (243)
                                  
Total price risk management assets $— $212 $28 $240 $— $291 $35 $326  $— $343 $22 $365 $— $291 $35 $326 
Marketable securities in non-qualified compensation plans
 21 — — 21 20 — — 20  20 — — 20 20 — — 20 
                                  
Total net assets $21 $212 $28 $261 $20 $291 $35 $346  $20 $343 $22 $385 $20 $291 $35 $346 
                                  
  
Liabilities
  
Commodity-based derivatives
  
Production-related oil and natural gas derivatives $— $(159) $— $(159) $— $(136) $— $(136) $— $(83) $— $(83) $— $(136) $— $(136)
Other natural gas derivatives —  (133)  (67)  (200) —  (162)  (90)  (252) —  (88)  (56)  (144) —  (162)  (90)  (252)
Power-related derivatives — —  (327)  (327) — —  (359)  (359) — —  (303)  (303) — —  (359)  (359)
                                  
Total commodity-based derivative liabilities —  (292)  (394)  (686) —  (298)  (449)  (747) —  (171)  (359)  (530) —  (298)  (449)  (747)
Interest rate derivatives designated as hedges
  
 
Cash flow hedges —  (100) —  (100) —  (69) —  (69) —  (16) —  (16) —  (69) —  (69)
Impact of master netting arrangements
 — 194 11 205 — 229 14 243  — 113 10 123 — 229 14 243 
                                  
Total price risk management liabilities $— $(198) $(383) $(581) $— $(138) $(435) $(573) $— $(74) $(349) $(423) $— $(138) $(435) $(573)
Other
 — —  (13)  (13) — —  (12)  (12) — —  (12)  (12) — —  (12)  (12)
                                  
  
Total net liabilities $— $(198) $(396) $(594) $— $(138) $(447) $(585) $— $(74) $(361) $(435) $— $(138) $(447) $(585)
                                  
  
Total $21 $14 $(368) $(333) $20 $153 $(412) $(239) $20 $269 $(339) $(50) $20 $153 $(412) $(239)
                                  
     On certain derivative contracts recorded as assets in the table above, we are exposed to the risk that our counterparties may not perform or post the required collateral. Based on our assessment of counterparty risk in light of the collateral our counterparties have posted with us (primarily in the form of letters of credit), we have determined that our exposure is primarily related to our production-related derivatives and is limited to nineten financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.

1113

     The following table presents the changes in our financial assets and liabilities included in Level 3 for the quarter and sixnine months ended JuneSeptember 30, 2011:
                                        
 Change in Fair Value Change in Fair Value       
 Balance at Reflected in Reflected in Balance at  Change in Fair Value Change in Fair Value   
 Beginning of Operating Operating End of  Balance at Reflected in Reflected in Balance at 
 Period Revenues(1) Expenses(2) Settlements Period  Beginning of Operating Operating End of 
 (In millions)  Period Revenues(1) Expenses(2) Settlements Period 
Quarter Ended June 30, 2011
 
   (In millions)   
Quarter Ended September 30, 2011
 
Assets $32 $(3) $— $(1) $28  $28 $(5) $— $(1) $22 
Liabilities  (416)  (5)  (5) 30  (396)  (396) 4  (1) 32  (361)
                      
Total $(384) $(8) $(5) $29 $(368) $(368) $(1) $(1) $31 $(339)
                      
  
Six Months Ended June 30, 2011
 
Nine Months Ended September 30, 2011
 
Assets $35 $(6) $— $(1) $28  $35 $(11) $— $(2) $22 
Liabilities  (447)  (3)  (6) 60  (396)  (447) 1  (7) 92  (361)
                      
Total $(412) $(9) $(6) $59 $(368) $(412) $(10) $(7) $90 $(339)
                      
 
(1) Includes approximately $6$1 million and $10 million of net losses that had not been realized through settlements for the quarter and sixnine months ended JuneSeptember 30, 2011.
 
(2) Includes approximately $4$1 million and $5 million of net losses that had not been realized through settlements for the quarter and sixnine months ended JuneSeptember 30, 2011.
     Below are the impacts of our commodity-based and interest rate derivatives to our statements of income and statements of comprehensive income (loss) for the quarters and sixnine months ended JuneSeptember 30:
                                                
 2011 2010  2011 2010 
 Other Other  Other Other 
 Operating Interest Comprehensive Operating Interest Comprehensive  Operating Interest Comprehensive Operating Interest Comprehensive 
 Revenues Expense Income (Loss) Revenues Expense Income (Loss)  Revenues Expense Income (Loss) Revenues Expense Income (Loss) 
 (In millions)  (In millions) 
Quarters ended June 30,
 
Quarters ended September 30,
 
Production-related derivatives $132 $— $3 $31 $— $3  $251 $— $2 $184 $— $2 
Other natural gas and power derivatives  (6) — —  (43) — —   (1) — —  (14) — — 
Total interest rate derivatives — 4  (34) — 4  (45) — 12  84(1) — 4  (43)
                          
Total $126 $4 $(31) $(12) $4 $(42) $250 $12 $86 $170 $4 $(41)
                          
  
Six months ended June 30,
 
Nine months ended September 30,
 
Production-related derivatives $23 $— $6 $284 $— $6  $274 $— $8 $468 $— $8 
Other natural gas and power derivatives  (7) — —  (26) — —   (8) — —  (40) — — 
Total interest rate derivatives — 8  (31) — 9  (46) — 20  53(1) — 13  (89)
                          
Total $16 $8 $(25) $258 $9 $(40) $266 $20 $61 $428 $13 $(81)
                          
(1)Includes $125 million related to the recognition of the accumulated other comprehensive loss associated with interest rate swaps on Ruby’s debt in conjunction with its deconsolidation (see Note 15) included in Loss on deconsolidation of subsidiary in the condensed consolidated statements of income.

1214

7.8. Property, Plant and Equipment
     Unevaluated capitalized costs of oil and natural gas operations were as follows:
         
  September 30,  December 31, 
  2011  2010 
  (In millions) 
U.S.
        
Acquisition $338  $407 
Exploration  119   130 
       
Total U.S  457   537 
       
Brazil & Egypt
        
Acquisition  34   45 
Exploration  45   203 
       
Total Brazil & Egypt  79   248 
      ��
Worldwide $536  $785 
       
     During the quarter and nine months ended September 30, 2011, we released approximately $42 million and $86 million of our unevaluated capitalized costs to our Brazilian full cost pool upon the completion of our evaluation of certain exploratory wells drilled in 2009 and 2010. During the third quarter of 2011, we also released approximately $94 million related to a certain Brazilian development project where we were recently denied a necessary environmental permit. These actions contributed to a ceiling test charge recorded on the Brazilian full cost pool during the third quarter of 2011. See Note 3 for a further discussion. At September 30, 2011, we have total oil and natural gas capitalized costs of approximately $207 million and $71 million in Brazil and Egypt, of which $8 million and $71 million are unevaluated capitalized costs.

15

9. Debt, Other Financing Obligations and Other Credit Facilities
                
 June 30, December 31,  September 30, December 31, 
 2011 2010  2011 2010 
 (In millions)  (In millions) 
Short-term financing obligations, including current maturities $618 $489  $350 $489 
Long-term financing obligations 13,594 13,517  12,531 13,517 
          
Total $14,212 $14,006  $12,881 $14,006 
          
     Changes in Financing Obligations.During the sixnine months ended JuneSeptember 30, 2011, we had the following changes in our financing obligations:
            
             Book Value Cash 
 Book Value Cash  Increase (Decrease) Received (Paid) 
Company Interest Rate Increase (Decrease) Received (Paid)  Interest Rate (In millions) 
  (In millions) 
Issuances
  
Ruby Pipeline, L.L.C. credit facility variable $391 $391  variable $393 $393 
Southern Natural Gas Company, L.L.C. (SNG) notes due 2021  4.40 % 300 297   4.40% 300 297 
El Paso Exploration and Production Company (EPEP) revolving credit facility variable 925 918 
El Paso revolving credit facility variable 571 562 
EP Energy Corporation (EPE) revolving credit facility variable 1,425 1,418 
El Paso revolving credit facilities variable 1,619 1,610 
El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC) revolving credit facility variable 815 808  variable 965 958 
EPPOC notes due 2021  5.00% 497 492 
          
Increases through June 30, 2011
 $3,002 $2,976 
Increases through September 30, 2011
 $5,199 $5,168 
          
Repayments, repurchases, and other
  
EPEP revolving credit facility variable $(825) $(825)
El Paso revolving credit facility variable  (796)  (796)
EPE revolving credit facility variable $(1,175) $(1,175)
El Paso revolving credit facilities variable  (1,046)  (1,046)
EPPOC revolving credit facility variable  (715)  (715) variable  (1,235)  (1,235)
EPPOC notes due 2011  7.76%  (37)  (37)
El Paso notes due 2011  7.00 %   (105)  (105)  7.00% — 7.625%  (332)  (332)
El Paso notes due 2012 through 2032  7.25% - 12.00 %   (347)  (410)
El Paso notes due 2012 through 2037  6.875% — 12.00%  (999)  (1,159)
Ruby Pipeline, L.L.C. credit facility(1)
 variable  (1,487) — 
Other various  (8)  (10) various  (13)  (17)
          
Decreases through June 30, 2011
 $(2,796) $(2,861)
Decreases through September 30, 2011
 $(6,324) $(5,001)
          
     In July 2011, our debt increased by approximately $650 million net of an additional $274 million of debt we repurchased under our early tender offer. We anticipate spending up to an additional $438 million in August 2011 to buy back additional debt. In conjunction with these transactions we anticipate recording losses of approximately $100 million during the third quarter of 2011. The majority of the July debt increase diversified our sources of liquidity.
(1)In September 2011, the Ruby debt obligations became non-recourse to us and we deconsolidated Ruby. As a result, we no longer reflect the debt obligations or related interest rate swaps on our balance sheet (see Note 15).
     Repurchase of Senior Notes.Notes. During the sixnine months ended JuneSeptember, 30, 2011, we repurchased approximately $350 million$1.0 billion of our senior unsecured notes. In conjunction with these transactions, we recorded total losses on debt extinguishment of $27$101 million and $68$169 million during the quarter and sixnine months ended JuneSeptember 30, 2011. In September 2010, we exchanged debt with a principal value of approximately $348 million. In conjunction with this transaction we recorded a loss of $104 million consisting of $77 million of cash consideration paid to the holders of the senior notes and $27 million to write-off unamortized discount and debt issue costs.
     Refinancing of Revolving Credit Facilities.During the six months ended June 30,second quarter of 2011, we refinanced $3.25 billion in revolving credit facilities to extend their maturity to 2016. As part of the revolver refinancings, we reduced the overall borrowing capacity on the El Paso facility from $1.5 billion to $1.25 billion and increased the overall borrowing capacity on the EPPOC facility from $0.75 billion to $1.0 billion (expandable to $1.5 billion for certain expansion projects and acquisitions). Our current cost to borrow under thesethe facilities has increased to LIBOR plus 2.25 for El Paso, LIBOR plus 2.00 for EPBEPPOC and LIBOR plus 1.50 to 2.50 for EPEP.EPE. The El Paso facility collateral support now includes the general partnership interests in EPBEl Paso Pipeline Partners, L.P. (EPB) while certain collateral restrictions have been modified providing us the ability to sell up to 100 percent of our ownership interests in either El Paso Natural Gas Company (EPNG) or Tennessee Gas Pipeline Company, L.L.C. (TGP), or some combination thereof, to EPB. Upon achieving investment grade status by one of the rating agencies, collateral support on the El Paso facility will be eliminated. As of JuneSeptember 30, 2011, we were in compliance with all of our debt covenants of which there were no material changes from those reported in our 2010 Annual Report on Form 10-K.

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     Credit Facilities/Letters of CreditCredit.. We have various credit facilities in place, including the above revolvers, which allow us to borrow funds or issue letters of credit. During the first sixnine months of 2011, we increased the total letter of credit capacity under certain existing and new letter of credit facilities by $175 million with a weighted average fixed facility fee of 1.78 percent and maturities ranging from April 2012 to September 2014. In July 2011, our $500 million unsecured credit facility matured. As of JuneSeptember 30, 2011, the aggregate amount outstanding under all of our credit facilities was $0.4$1.3 billion (excluding $0.4 billion outstanding on the EPPOC $1.0 billion revolving credit facility) and $0.9in addition to $0.6 billion of letters of credit and surety bonds, issued, including $0.4 billion related to our price risk management activities and $0.2 billion related to Ruby as discussed below.activities. Our total available capacity under all of our facilities was approximately $2.5$1.3 billion as of JuneSeptember 30, 2011 (not including capacity available under the EPPOC $1.0 billion revolving credit facility). In July 2011, our $500 million unsecured credit facility matured.

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Ruby Pipeline Financing. During 2010, we entered into a seven-year amortizing $1.5 billion financing facility for our Ruby pipeline project (see Note 12) that requires principal payments at various dates through June 2017. As of June 30, 2011, we have utilized all of the available capacity under this facility. Our initial interest rate on amounts borrowed is LIBOR plus 3 percent which increases to LIBOR plus 3.25 percent for years three and four, and to LIBOR plus 3.75 percent for years five through seven assuming we refinance $700 million of the facility by the end of year four. If we do not refinance $700 million by the end of year four, the rate will be LIBOR plus 4.25 percent for years five through seven. In conjunction with entering into this facility, we entered into interest rate swaps that began converting the floating LIBOR interest rate to fixed interest rates in July 2011 on approximately $1.1 billion of total borrowings under this agreement. As of July 31, 2011, we also had $100 million outstanding ($170 million as of June 30, 2011) in letters of credit related to Ruby. Upon making certain permitting representations, and obtaining consents and/or waivers of certain customary conditions, our Ruby project financing obligations will become non-recourse to us.
8.10. Commitments and Contingencies
Legal Proceedings
Shareholder Class Actions. Beginning on October 17, 2011, multiple purported shareholder class actions were filed challenging the proposed acquisition of El Paso by KMI. The lawsuits were filed against both companies, an advisor and the El Paso board of directors. The shareholder class actions generally allege that the El Paso board breached its fiduciary duties to the shareholders by approving the transaction and that the two companies aided in the alleged breach. All of the shareholder class actions seek to enjoin the transaction. These actions have been filed in state district court in Harris County, Texas, and in Delaware Chancery Court. We expect that additional actions may be filed in the future. We believe these purported shareholder class actions are without merit and we intend to defend against them vigorously.
     Cash Balance Plan Lawsuit.In December 2004, a purported class action lawsuit entitledTomlinson, et al.v. El Paso Corporation and El Paso Corporation Pension Planwas filed in U.S. District Court for Denver, Colorado. The lawsuit alleges various violations of the Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act as a result of our change from a final average earnings formula pension plan to a cash balance pension plan. In 2010, a trial courtDistrict Court dismissed all of the claims in this matter. The plaintiffs appealed the dismissal of the case has been appealed.and in August 2011 the Court of Appeals for the Tenth Circuit affirmed the District Court’s decision. We believe that it is likely that the plaintiffs will seek United States Supreme Court review of the Tenth Circuit decision.
     Price Reporting Litigation.Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which were pending in Nevada, were dismissed. Appeals have been filed. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims are not currently determinable.
     MTBE. Certain of our subsidiaries used, produced, sold or distributed methyl tertiary-butyl ether (MTBE) as a gasoline additive. Various lawsuits were filed throughout the U.S. regarding the potential impact of MTBE on water supplies. The lawsuits have been brought by different parties, including state attorney generals, water districts and individual water companies seeking different remedies against us and many other defendants, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation (MDL) in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. Eighty-eight of the cases have been settled or dismissed, and all of the settlements have been or are expected to be substantially funded by insurance. We have eleven remaining lawsuits, all pending in the MDL. Of these remaining lawsuits, it is likely that our insurers will assert denial of coverage on nine of the most-recently filed lawsuits. Based upon discovery conducted to date, our share of the relevant markets upon which alleged damages have been historically allocated among individual defendants is relatively small. In addition, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us as well as availability of insurance coverages. Therefore, our costs and legal exposure related to the remaining lawsuits are not currently determinable.

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     In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of JuneSeptember 30, 2011, we had approximately $40 million accrued, which has not been reduced by $3$2 million of related insurance receivables, for all of our outstanding legal proceedings.
Rates and Regulatory Matters
     EPNG Rate Case.In April 2010, the FERC approved an offer of settlement which increased EPNG’s base tariff rates, , effective January 1, 2009. As part of the settlement, EPNG made refunds to its customers in 2010. The settlement resolved all but four issues in the rate proceeding. In January 2011, the Presiding Administrative Law Judge issued a decision that for the most part found against EPNG on the four issues. EPNG has appealed those decisions to the FERC and may also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.
     In September 2010, EPNG filed a new rate case with the FERC proposing an increase in its base tariff rates which would increase revenue by approximately $100 million annually over previously effective tariff rates. It is uncertain whether such an increase will be achieved in the context of any settlement between EPNG and its customers or following the outcome of a hearing in the rate case. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. A hearing commenced in late October 2011. It is uncertain whether the requested increase will be achieved in the context of any settlement between EPNG and its customers or following the outcome of a hearing in the rate case. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.
     TGP Rate Case.In November 2010, TGP filed a rate case with the FERC proposing an increase in its base tariff rates of approximately $200 million annually over previously effective tariff rates. It is uncertain whether such an increase will be achieved inand the context of any settlement between TGP and its customers or following the outcomeimplementation of a hearingfuel volume tracker with a reduction in the rate case.TGP’s fuel retention rates, among other things. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. In September 2011, TGP filed a proposed settlement with the FERC, which was uncontested by its customers. The proposed settlement provides for, among other things, an increase in TGP’s revenues of approximately $60 million to $70 million annually, net of revenues from excess fuel retention, significant contract extensions until October 2014 and a requirement to file new rates to be effective no earlier than April 2014 but no later than November 2015. Although the final outcome isFERC has not currently determinable,yet approved the proposed settlement, we believe our accruals established for this matter are adequate.
     CIG Rate Case.In May 2011, Colorado Interstate Gas Company, L.L.C. (CIG) reached aRate Case.In August 2011, the FERC approved an uncontested pre-filing settlement with all of its shippers of aCIG’s rate case required under the terms of a previous settlement. CIG has filed the proposedThe settlement with the FERC whichgenerally provides for CIG’s current tariff rates to continue until its next general rate case which will be effective after October 1, 2014 but no later than October 1, 2016. At this time, the FERC has not ruled on that petition and the outcome of this matter is not determinable.
Environmental Matters
     We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At JuneSeptember 30, 2011, our accrual was approximately $170$186 million for environmental matters, which has not been reduced by $19 million for amounts to be paid directly under government sponsored programs or through contractual arrangements with third parties. Our accrual includes approximately $167$183 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $3 million for related environmental legal costs.

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     Our estimates of potential liability range from approximately $170$186 million to approximately $355$327 million. Our recorded environmental liabilities reflect our current estimates of amounts we will expend on remediation projects in various stages of completion. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:
                
 June 30, 2011  September 30, 2011 
Sites Expected High  Expected High 
 (In millions)  (In millions) 
Operating $8 $12  $8 $12 
Non-operating 149 307 
Non-operating. 164 279 
Superfund 13 36  14 36 
          
Total $170 $355  $186 $327 
          
     Superfund Matters.Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated, as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as

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Superfund, or state equivalents for 28 active sites. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these issuesmatters are included in the previously indicated estimates for Superfund sites.
     For the remainder of 2011, we estimate that our total remediation expenditures will be approximately $30$20 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $24$27 million in the aggregate for the remainder of 2011 through 2015, including capital expenditures associated with the impact of the Environmental Protection Agency rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.
     It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Guarantees and Other Contractual Commitments
     Guarantees and Indemnifications.We have guarantees and indemnifications with a maximum stated value of approximately $0.8$0.7 billion, primarily related to indemnification arrangements associated with the sale of ANR Pipeline Company in 2007 and certain legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 7.9. We are unable to estimate a maximum exposure of our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
     As of JuneSeptember 30, 2011, we have recorded obligations of $18$17 million related to our guarantee and indemnification arrangements. We believe that our guarantee and indemnification agreements for which we have not recorded a liability are not probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, among other considerations.
     For a further discussion of our guarantees, indemnifications, purchase obligations, and other commercial commitments see our 2010 Annual Report on Form 10-K.

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9.11. Retirement Benefits
     Components of Net Benefit Cost.The components of net benefit cost are as follows for the quarters and sixnine months ended JuneSeptember 30:
                                                                
 Quarters Ended June 30, Six Months Ended June 30,  Quarters Ended September 30, Nine Months Ended September 30, 
 Other Other  Other Other 
 Pension Postretirement Pension Postretirement  Pension Postretirement Pension Postretirement 
 Benefits Benefits Benefits Benefits  Benefits Benefits Benefits Benefits 
 2011 2010 2011 2010 2011 2010 2011 2010  2011 2010 2011 2010 2011 2010 2011 2010 
 (In millions)  (In millions) 
Service cost $6 $4 $— $— $11 $9 $— $—  $5 $5 $— $— $16 $14 $— $— 
Interest cost 27 29 7 9 53 57 15 17  27 29 8 8 80 86 23 25 
Expected return on plan assets  (37)  (40)  (3)  (4)  (73)  (79)  (7)  (7)  (36)  (39)  (4)  (3)  (109)  (118)  (11)  (10)
Amortization of net actuarial loss (gain) 23 18  (1)  (1) 46 37  (1)  (2) 23 18 — — 69 55  (1)  (2)
Amortization of prior service cost — 1 — — — 1 — — 
Amortization of prior service cost (credit) — — —  (1) — 1 —  (1)
                                  
Net benefit cost $19 $12 $3 $4 $37 $25 $7 $8  $19 $13 $4 $4 $56 $38 $11 $12 
                                  
10.12. Equity and Preferred Stock of SubsidiariesNoncontrolling Interests
     Convertible Perpetual Preferred Stock.In March 2011, we exercised our mandatory conversion right related to our $750 million of convertible perpetual preferred stock. Upon conversion, holders of our convertible preferred stock received approximately 57.9 million shares of common stock (approximately 77.2295 shares of El Paso common stock for each share of preferred stock converted).
     Common and Preferred Stock Dividends.The table below shows the amount of dividends paid and declared (in millions, except per share amount):
                
 Common Stock Convertible Preferred Stock Common Stock Convertible Preferred Stock 
 ($0.01/Share) (4.99%/Year) ($0.01/Share) (4.99%/Year) 
Amount paid through June 30, 2011 $14 $9 
Amount paid in July 2011 $8 $— 
Declared in July 2011: 
Amount paid for the nine months ended September 30, 2011 $22 $9 
Amount paid in October 2011 $7 $— 
Declared in October 2011: 
Date of declaration July 14, 2011 —  October 6, 2011 — 
Payable to shareholders on record September 2, 2011 —  December 2, 2011 — 
Date payable October 3, 2011 —  January 3, 2012 — 
     Dividends on our common stock and convertible preferred stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. For 2011, we expect dividends paid on our common and preferred stock will be taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes. Our ability to pay dividends can be impacted by certain restrictions as further described in our 2010 Annual Report on Form 10-K.
     Noncontrolling InterestInterests in EPB.We are the general partner of EPB, a master limited partnership (MLP) formed in 2007. As of JuneSeptember 30, 2011, we own a 44 percent interest in EPB (2 percent general partner interest and a 42 percent limited partner interest). During the first halfnine months of 2011, we contributed the remaining 40 percent ownership interest in SNG and an additional 28 percent interest in CIG to EPB in exchange for approximately $1.4 billion. EPB raised the funds for the acquisitions primarily through $948 million in proceeds from the issuance of 28.5 million common units and $444 million in borrowings under the EPPOC revolving credit facility. Our consolidated statement of equity for the sixnine months ended JuneSeptember 30, 2011 reflects the issuance of the EPB common units as an increase of $610 million to noncontrolling interests and an increase of $338 million to El Paso Corporation’s additional paid-in capital. Our net income attributable to El Paso Corporation, together with the increase in El Paso Corporation’s additional paid-in capital for the sixnine months ended JuneSeptember 30, 2011 totaled $662$294 million.
     In accordance with its partnership agreement, EPB is obligated to make quarterly distributions of available cash to its unitholders. We receive our share of these cash distributions through our limited partner ownership interest, general partner interest, and incentive distribution rights (IDRs) we are entitled to as the general partner. Prior to February 15, 2011, we held subordinated units in EPB. Upon payment of the quarterly cash distribution for the fourth quarter of 2010, the financial tests required for the conversion of subordinated units into common units were

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satisfied. As a result, our subordinated units were converted on February 15, 2011 into common units on a one-for-one basis effective January 3, 2011.

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     To the extent that the consideration for the sales of assets to EPB is not in the form of additional equity in EPB, our interest in our assets becomes diluted over time. However our economic interest will benefit from the receipt of incentive distributions in accordance with the partnership agreement.
     Our IDRs provide for the receipt of an increasing portion of quarterly distributions based on the level of distribution to all unitholders. We can elect to relinquish the right to receive incentive distribution payments and reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments would be set. We are currently entitled to receive the maximum level of incentive distributions.
     Preferred Stock of Subsidiaries.During the first six months of 2011, our partner on our Ruby pipeline project, Global Infrastructure Partners (GIP), contributed an additional $30 million and as of June 30, 2011 had contributed $700 million, including approximately $555 million for a convertible preferred interest in Ruby Pipeline Holding Company, L.L.C. (Ruby) and $145 million for a convertible preferred equity interest in Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains). GIP receives a dividend at a 15 percent annual rate on its preferred interests in Cheyenne Plains payable quarterly. Effective in the third quarter of 2011, GIP will receive a dividend at a 13 percent annual rate on its convertible preferred interests in Ruby payable quarterly.
     We paid preferred dividends of $5 million and $10 million on GIP’s preferred interest in Cheyenne Plains for the quarters and six months ended June 30, 2011 and 2010. Also, for the quarter and six months ended June 30, 2011, we accrued $18 million and $35 million related to the return on GIP’s preferred interest in Ruby. Both the preferred dividends and the return on GIP’s preferred interests are reflected in net income attributable to noncontrolling interests on our income statement. GIP’s preferred interests in Cheyenne Plains and Ruby, including accrued preferred returns, are classified between liabilities and equity on our balance sheet. For a further discussion of the Ruby transaction,
see Note 12.
Net Income Attributable to Noncontrolling Interests.The components of net income attributable to noncontrolling interests on our statements of income are as follows for the quarters and sixnine months ended JuneSeptember 30:
                                
 Quarters Ended June 30, Six Months Ended June 30,  Quarters Ended September 30, Nine Months Ended September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
EPB $54 $24 $106 $50  $55 $25 $161 $75 
Preferred Stock of Cheyenne Plains 5 5 10 10 
Preferred Stock of Ruby 18 — 35 — 
Preferred Stock of Cheyenne Plains (Note 15) 5 5 15 15 
Preferred Stock of Ruby (Note 15) 15 11 50 11 
                  
Net income attributable to noncontrolling interests $77 $29 $151 $60  $75 $41 $226 $101 
                  

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11.13. Business Segment Information
     As of JuneSeptember 30, 2011, our business consists of the following segments: Pipelines, Exploration and Production, and Marketing. We also have other business and corporate activities. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. A further discussion of each segment follows.
     Pipelines.Our Pipelines segment provides natural gas transmission, storage, and related services. As of JuneSeptember 30, 2011, we conducted our activities primarily through eight wholly or majoritypartially owned interstate pipeline systems and equity interests in twothree transmission systems. In addition to the storage capacity in our wholly and majority owned pipelines systems, we also own or have interests in three underground natural gas storage facilities and two LNG terminal facilities.
     Exploration and Production.Our Exploration and Production segment is engaged in the exploration for and the acquisition, development and production of oil, natural gas and NGL, in the U.S., Brazil and Egypt.
     Marketing.Our Marketing segment markets on behalf of our Exploration and Production segment and manages the price risks associated with our oil and natural gas production as well as manages our remaining legacy trading portfolio.
     Other.Our other activities include our corporate general and administrative functions, midstream operations and miscellaneous businesses.
     Beginning January 1, 2011, we use segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business segments. We believe Segment EBIT is useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. Segment EBIT is defined as net income (loss) adjusted for interest and debt expense and income taxes. It does not reflect a reduction for any amounts attributable to noncontrolling interests. Segment EBIT may not be comparable to measurements used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows. Our 2010 amounts have been conformed to reflect our current performance measure.
     Below is a reconciliation of our Segment EBIT to our net income for the periods ended JuneSeptember 30:
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Segment EBIT $616 $552 $1,011 $1,400  $(181) $513 $830 $1,913 
Interest and debt expense  (239)  (284)  (479)  (527)  (242)  (255)  (721)  (782)
Income tax expense  (38)  (82)  (57)  (268)
Income tax benefit (expense) 130  (75) 73  (343)
                  
Net income 339 186 475 605 
Net income (loss)  (293) 183 182 788 
Net income attributable to noncontrolling interests  (77)  (29)  (151)  (60) (75) (41) (226) (101)
                  
Net income attributable to El Paso Corporation $262 $157 $324 $545 
Net income (loss) attributable to El Paso Corporation $(368) $142 $(44) $687 
                  

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     The following table reflectstables reflect our segment results for the quarters and sixnine months ended JuneSeptember 30:
                                                
 Segments      Segments       
 Exploration          Exploration         
 Pipelines and Production Marketing Other Eliminations Total  Pipelines and Production Marketing Other Eliminations Total 
 (In millions)  (In millions)        
Quarter Ended June 30, 2011
 
Quarter Ended September 30, 2011
 
  
Revenue from external customers $684 $379(1) $172 $1 $— $1,236  $743 $481(1) $177 $2 $— $1,403 
Intersegment revenue 38  156(1)  (192) 1  (3) —  17  172(1)  (186) —  (3) — 
Operation and maintenance 211 97 2 12 1 323  213 114 — 39 — 366 
Loss on deconsolidation of subsidiary  600(2) — — — — 600 
Ceiling test charges — 152 — — — 152 
Depreciation, depletion and amortization 110 146 — 6 — 262  136 157 — 6 — 299 
Earnings from unconsolidated affiliates 25 1 — 6 — 32 
Earnings (losses) from unconsolidated affiliates 24  (3) — 15 — 36 
Segment EBIT 428 250  (21)  (41)(2) — 616   (209) 183  (10)  (145)(3) —  (181)
  
Quarter Ended June 30, 2010
 
Quarter Ended September 30, 2010
 
  
Revenue from external customers $668 $199(1) $133 $18 $— $1,018  $680 $340(1) $174 $19 $— $1,213 
Intersegment revenue 12  170(1)  (181) 5  (6) —  12  179(1)  (190) 7  (8) — 
Operation and maintenance 195 91 1  (2) — 285  220 87  (3) 23 — 327 
Ceiling test charges — 14 — — — 14 
Depreciation, depletion and amortization 110 128 — 4 — 242  111 117 — 11 — 239 
Earnings (losses) from unconsolidated affiliates  107(3)  (1) — 5 — 111  28  (2) — 2 — 28 
Segment EBIT 472 103  (49) 26 — 552  375 261  (12)  (111)(3) — 513 
 
(1) Revenues from external customers include gains of $132$251 million and $31$184 million for the quarters ended JuneSeptember 30, 2011 and 2010 related to our financial derivative contracts associated with our oil and natural gas production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.segment.
 
(2)Reflects a non-cash loss of approximately $475 million based on the difference between the net carrying value of Ruby and the estimated fair value of our investment in Ruby and a non-cash loss of approximately $125 million related to the recognition of the accumulated other comprehensive loss associated with interest rate swaps on the Ruby debt (see Note 15).
(3) Includes loss on debt extinguishment of approximately $27$101 million and $104 million for the quarters ended September 30, 2011 and 2010 primarily related to debt repurchases.
(3)Includes a gain of approximately $80 million related to the sale of certain of our interests in Mexican pipeline and compression assets.

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 Segments      Segments       
 Exploration          Exploration         
 Pipelines and Production Marketing Other Eliminations Total  Pipelines and Production Marketing Other Eliminations Total 
 (In millions)  (In millions)          
Six Months Ended June 30, 2011
 
Nine Months Ended September 30, 2011
 
  
Revenue from external customers $1,387 $463(1) $373 $2 $— $2,225  $2,130 $944(1) $550 $4 $— $3,628 
Intersegment revenue 88  322(1)  (405) 2  (7) —  105  494(1)  (591) 2  (10) — 
Operation and maintenance 401 198 4 25 — 628  614 312 4 65  (1) 994 
Loss on deconsolidation of subsidiary  600(2) — — — — 600 
Ceiling test charges — 152 — — — 152 
Depreciation, depletion and amortization 224 280 — 12 — 516  360 437 — 18 — 815 
Earnings (losses) from unconsolidated affiliates 50  (1) — 13 — 62  74  (4) — 28 — 98 
Segment EBIT 927 219  (35)  (100)(2) — 1,011  718 402  (45)  (245)(3) — 830 
  
Six Months Ended June 30, 2010
 
Nine Months Ended September 30, 2010
 
  
Revenue from external customers $1,392 $626(1) $382 $19 $— $2,419  $2,072 $966(1) $556 $38 $— $3,632 
Intersegment revenue 25  390(1)  (411) 4  (8) —  37  569(1)  (601) 11  (16) — 
Operation and maintenance 379 190 3 14 — 586  599 275 — 37 — 911 
Ceiling test charges — 16 — — — 16 
Depreciation, depletion and amortization 216 235 — 9 — 460  327 352 — 20 — 699 
Earnings (losses) from unconsolidated affiliates  129(3)  (1) — 11 — 139   157(4)  (3) — 13 — 167 
Segment EBIT 924 493  (32) 15 — 1,400  1,299 754  (44)  (96)(3) — 1,913 
 
(1) Revenues from external customers include gains of $23$274 million and $284$468 million for the sixnine months ended JuneSeptember 30, 2011 and 2010 related to our financial derivative contracts associated with our oil and natural gas production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.segment.
 
(2)Reflects a non-cash loss of approximately $475 million based on the difference between the net carrying value of Ruby and the estimated fair value of our investment in Ruby and a non-cash loss of approximately $125 million related to the recognition of the accumulated other comprehensive loss associated with interest rate swaps on the Ruby debt (see Note 15).
(3) Includes loss on debt extinguishment of approximately $68$169 million and $104 million for the nine months ended September 30, 2011 and 2010 primarily related to debt repurchases.
 
(3)(4) Includes a gain of approximately $80 million for the nine months ended September 30, 2010 related to the sale of certain of our interests in Mexican pipeline and compression assets.
Total assets by segment are presented below:
                
 June 30, December 31,  September 30, December 31, 
 2011 2010  2011 2010 
 (In millions)  (In millions) 
Pipelines(1) $20,824 $19,651  $18,396 $19,651 
Exploration and Production 4,999 4,657  4,724 4,657 
Marketing 210 222  182 222 
Other 989 943  960 943 
          
Total segment assets 27,022 25,473  24,262 25,473 
     
Eliminations  (64)  (203)  (184)  (203)
          
Total consolidated assets $26,958 $25,270  $24,078 $25,270 
          
(1)Reflects the deconsolidation of Ruby in the third quarter of 2011.

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12. Variable Interest Entities and14. Accounts Receivable Sales Programs
Ruby/Cheyenne Plains.As of June 30, 2011 GIP, our partner in the Ruby pipeline project, had contributed approximately $700 million in exchange for convertible preferred equity interests in Ruby and Cheyenne Plains. We currently consolidate Ruby and Cheyenne Plains as variable interest entities as we are the primary beneficiary of the entities that own the Ruby pipeline project and the Cheyenne Plains pipeline. GIP’s preferred interests are classified between liabilities and equity on our balance sheet since the events that require redemption of those interests are not entirely within our control and are not certain to occur. GIP will hold its preferred interest in Cheyenne Plains until certain remaining customary conditions with respect to the operations of the Ruby pipeline are either satisfied or waived by our partner and lenders, at which time these interests will be transferred back to us in exchange for additional preferred interests in Ruby. GIP’s preferred equity interest in Ruby is convertible at any time into common equity; however, it is subject to mandatory conversion to common equity upon the satisfaction of certain requirements, including Ruby entering into additional firm transportation agreements of 250 MMcf/d. Approximately 1.1 Bcf/d of the total design capacity of 1.5 Bcf/d on our Ruby pipeline is currently subscribed. Our ability to enter into additional firm transportation agreements will be based on future market conditions.
     If the customary conditions described above are not satisfied or waived by December 2011, GIP has the option to convert its preferred interest in Cheyenne Plains to a common interest and/or be repaid in cash for its remaining investments in Cheyenne Plains and Ruby including a 15 percent annual return on these investments. Our obligation to repay these amounts is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in EPB.
     Upon satisfaction or waiver of the conditions noted above, we will deconsolidate Ruby and reflect it as an equity method investment. Upon deconsolidation, we will be required to assess the impairment of our equity investment at fair value, which is a different model than we currently use while consolidated. Currently, we assess recoverability of the Ruby pipeline based on estimated undiscounted cash flows. As a result of assuming construction and cost overrun risk with the project, we anticipate that we will be required to record a non-cash loss on our investment in Ruby upon deconsolidation in an amount ranging from $300 million to $500 million based on our assessment of the estimated fair value of our investment in Ruby. The ultimate loss will be based on a number of factors, including actual market conditions at that time. For additional information on our Ruby pipeline project, see Note 10.
     Accounts Receivable Sales Programs.We participate in accounts receivable sales programs where several of our pipeline subsidiaries sell receivables in their entirety to a third-party financial institution (through wholly-owned special purpose entities). The sale of these accounts receivable (which are short-term assets that generally settle within 60 days) qualify for sale accounting. The third party financial institution involved in these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.
     In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. The table below contains information related to our accounts receivable sales programs.
                                
 Quarter Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Accounts receivable sold to the third-party financial institution(1)
 $597 $563 $1,204 $1,206  $647 $599 $1,851 $1,805 
Cash received for accounts receivable sold under the programs 343 331 696 786  356 338 1,051 1,124 
Deferred purchase price related to accounts receivable sold 254 232 508 420  291 261 800 681 
Cash received related to the deferred purchase price 250 243 498 480  295 266 793 746 
Amount paid in conjunction with terminated programs(2)
 — — — 90  — — — 90 
 
(1) During the quarters and sixnine months ended JuneSeptember 30, 2011 and 2010, losses recognized on the sale of accounts receivable were immaterial.
 
(2) In January 2010, we terminated our previous accounts receivable sales programs and paid $90 million to acquire the related senior interests in certain receivables under those programs. See our 2010 Annual Report on Form 10-K for further information.

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 June 30, December 31,  September 30, December 31, 
 2011 2010  2011 2010 
 (In millions)  (In millions) 
Accounts receivable sold and held by third-party financial institution $217 $210  $213 $210 
Uncollected deferred purchase price related to accounts receivable sold(1)
 99 89  96 89 
 
(1) Initially recorded at an amount which approximates its fair value as a Level 2 measurementmeasurement.
     The deferred purchase price related to the accounts receivable sold is reflected as other accounts receivable on our balance sheet. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the accounts receivable sales programs as operating cash flows on our statement of cash flows. Under the accounts receivable sales programs, we service the underlying receivables for a fee. The fair value of these servicing agreements, as well as the fees earned, were not material to our financial statements for the quarters and sixnine months ended JuneSeptember 30, 2011 and 2010.

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13.15. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
     Our net investments in and earnings (losses) from our unconsolidated affiliates are as follows as of JuneSeptember 30, 2011 and December 31, 2010 and for the quarters and sixnine months ended JuneSeptember 30:
                                                
 Earnings (Losses) from  Earnings (Losses) from 
 Investment Unconsolidated Affiliates  Investment Unconsolidated Affiliates 
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, December 31, June 30, June 30,  September 30, December 31, September 30, September 30, 
 2011 2010 2011 2010 2011 2010  2011 2010 2011 2010 2011 2010 
 (In millions) (In millions)  (In millions) (In millions) 
Net Investment and Earnings (Losses)
  
Four Star(1)
 $366 $393 $1 $(1) $(1) $(1)
Ruby $1,069 $— $(1) $— $(1) $— 
Citrus(2)(1)
 872 822 24 25 49 40  897 822 25 27 74 67 
Four Star(2)
 351 393  (3)  (2)  (4)  (3)
Gulf LNG(3)
 259 266 — — — —  237 266  (1)  (1)  (1)  (1)
Bolivia-to-Brazil Pipeline 103 104 1 4 3 9  108 104 10 1 13 10 
Other(4)
 89 88 6 83 11 91  94 88 6 3 17 94 
                          
Total $1,689 $1,673 $32 $111 $62 $139  $2,756 $1,673 $36 $28 $98 $167 
                          
 
(1)We recorded amortization of our purchase cost in excess of the underlying net assets of Four Star Oil & Gas Company (Four Star) of $9 million for each of the quarters ended June 30, 2011 and 2010 and $18 million and $19 million for the six months ended June 30, 2011 and 2010.
(2) As of JuneSeptember 30, 2011, we had outstanding receivables of approximately $72$37 million, included in other long term assets, related to a promissory note from Citrus whereby we will lend up to $150 million.
 
(2)We recorded amortization of our purchase cost in excess of the underlying net assets of Four Star Oil and Gas Company (Four Star) of $8 million and $9 million for the quarters ended September 30, 2011 and 2010 and $26 million and $28 million for the nine months ended September 30, 2011 and 2010.
(3) As of JuneSeptember 30, 2011 and December 31, 2010, we had outstanding advances and receivables of $144$150 million and $85 million, included in other long term assets, related to our investment in Gulf LNG. On October 1, 2011, the Gulf LNG Clean Energy project was placed in service.
 
(4) Includes our investment in Gasoductos de Chihuahua for the quarter and sixnine months ended JuneSeptember 30, 2010. In April 2010, we completed the sale of our interest in this investment and recorded a pretax gain of approximately $80 million. See Note 2.
     Below is summarized financial information of our proportionate share of the operating results of our unconsolidated affiliates for the quarters and six months ended June 30, 2011 and 2010.
                 
  Quarters Ended  Six Months Ended 
  June 30,  June 30, 
  2011  2010  2011  2010 
      (In millions)     
Summarized Financial Information
                
Operating results data:                
Operating revenues $169  $128  $297  $260 
Operating expenses  70   65   137   138 
Net income  34   41   74   79 
Ruby.As of September 30, 2011, we have an equity investment in the Ruby pipeline project totaling approximately $1,069 million. Prior to September 2011, we reflected Ruby Pipeline Holding Company, L.L.C. (Ruby) as a consolidated variable interest entity because we were its primary beneficiary. In mid-September 2011, we met certain conditions of our lenders and our partner, Global Infrastructure Partners (GIP), and El Paso’s guarantee of GIP’s preferred interests in Ruby and Cheyenne Plains Investment Company, L.L.C. (Cheyenne Plains) expired. Accordingly, we no longer reflect approximately $769 million of preferred interests in subsidiaries between liabilities and equity on our balance sheet, which included $700 million of GIP’s investment in preferred stock of subsidiaries and $69 million in accrued preferred returns. As a result of us meeting these conditions, GIP transferred its $145 million convertible preferred stock in Cheyenne Plains to us in exchange for additional preferred stock in Ruby. Following these events, Ruby and Cheyenne Plains are no longer considered variable interest entities. Although we continue to operate the Ruby pipeline, we do not have a controlling financial interest in Ruby; therefore, we deconsolidated it prospectively in our financial statements.
     Prior to deconsolidation, Ruby’s individual assets and liabilities were reflected on our balance sheet, Ruby’s consolidated financial results were reflected in our income statement, and GIP’s returns on its preferred interests in Ruby and Cheyenne Plains were recorded in net income attributable to noncontrolling interests on our income statement. Upon Ruby’s deconsolidation in mid-September 2011, we no longer reflected the individual assets and liabilities of Ruby on our balance sheet and began recording Ruby’s earnings in earnings (losses) from unconsolidated affiliates on our income statement. At the time of deconsolidation, amounts on our balance sheet consisted primarily of approximately $3,673 million in property, plant and equipment, $348 million in regulatory and other assets, $125 million in price risk management liabilities associated with interest rate swaps on Ruby’s debt, $138 million in other liabilities, and $1,447 million in long term debt. For a further discussion of Ruby, see Notes 9 and 12 and our 2010 Annual Report on Form 10-K.

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     Upon deconsolidation, we were required to assess our investment in Ruby for impairment based on fair value, which is a different model than assessing recoverability of the Ruby pipeline based on estimated undiscounted cash flows while it was consolidated. Our fair value assessment was based on a number of factors, including the present value of anticipated distributable cash flows to be produced from the underlying operations of the Ruby investment. Determining these cash flows required the use of assumptions related to the future demand for Ruby’s capacity, forecasted commodity prices and interest rates, anticipated economic conditions, the timing of GIP’s conversion of their preferred interest into a common equity interest, and other inputs, many of which are not available as observable market data. As a result, our estimate of fair value was a Level 3 fair value measurement. As a result of the deconsolidation of Ruby and our fair value assessments, we recorded a third quarter non-cash loss of approximately $475 million based on the difference between the net carrying value in Ruby and the estimated fair value of our investment in Ruby. We also recorded a non-cash loss of $125 million related to the recognition of the accumulated other comprehensive loss associated with interest rate swaps on Ruby’s debt. Subsequent to deconsolidation, Ruby’s interest rate swaps continue to hedge Ruby’s project level debt.
Summarized Financial Information of Unconsolidated Affiliates.Below is summarized financial information of our proportionate share of the operating results of our unconsolidated affiliates before preferred interests for the quarters and nine months ended September 30, 2011 and 2010.
                 
  Quarters Ended  Nine Months Ended 
  September 30,  September 30, 
  2011  2010  2011  2010 
  (In millions) 
Summarized Financial Information
                
Operating results data:                
Operating revenues $181  $126  $478  $386 
Operating expenses  95   63   264   201 
Net income  46   40   120   119 
     We received distributions and dividends from our unconsolidated affiliates of $19$17 million and $21 million for each of the quarters ended JuneSeptember 30, 2011 and 2010 and $31$48 million and $36$53 million for the sixnine months ended JuneSeptember 30, 2011 and 2010. Our transactions with unconsolidated affiliates were not material to our operating results during the quarters and sixnine months ended JuneSeptember 30, 2011 and 2010.
     Other Investment-Related Matters.We currently have outstanding disputes and other matters related to an investment in two Brazilian power plant facilities (Manaus/Rio Negro) formerly owned by us. We have filed lawsuits to collect amounts due to us (approximately $74$62 million of Brazilian reais-denominated accounts receivable) by the plants’ power purchaser, which are also guaranteed by the purchaser’s parent, Eletrobras, Brazil’s state-owned utility. The power utility that purchased the power from these facilities and its parent have asserted counterclaims that would largely offset our accounts receivable. Absent resolution of these matters through settlement, we anticipate that the ultimate resolution will likely occur through legal proceedings in the Brazilian courts. We believe the receivables are collectible and therefore have not established an allowance against the receivables owed. We have reviewed our obligations under the power purchase agreements and have accrued what we believe is an appropriate amount in relation to the asserted counterclaims. We believe the remaining counterclaims are without merit. Based on the anticipated timing of the resolution of the legal proceedings, we have classified our accounts receivable and the accrual for the counterclaims as a non-current asset and liability in our financial statements.

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     Our project companies that previously owned the Manaus and Rio Negro power plants have also been assessed approximately $85$75 million of Brazilian reais-denominated ICMS taxes by the Brazilian taxing authorities for payments received by the companies from the plants’ power purchaser from 1999 to 2001. By agreement, the power purchaser has been indemnifying our project companies for these ICMS taxes, along with related interest and penalties. In the third quarter of 2010, a court hearing the Rio Negro case seized funds from certain of El Paso’s Rio Negro bank accounts in partial satisfaction of and as security for this potential tax liability. In order to prevent collection efforts by the tax authorities for this matter against our project companies, security must be provided for the potential tax liability to the court’s satisfaction. Although theThe power purchaser and the taxing authorities could not previously agree upon the security to be provided, it is our understanding that they have now agreed upon the posting of shares in a subsidiary of the power purchaser’s parent as security. The court hearing the Rio Negro case has now accepted these shares as security. We are awaiting a similar decision bysecurity and we have been advised that the court hearing the Manaus case. Upon acceptance bycase has now ruled in a similar fashion. The power purchaser asked the courtscourt hearing the Rio Negro case to vacate its order encumbering the assets belonging to our Rio Negro project company and its shareholders. That court has now lifted its order in respect of the shares as security, the power purchaser will then ask the court to vacate any orders encumbering our bank accounts and other assets and to refund to us any cash previously seized.project company’s assets. Until this tax matter is fully resolved, our ability to collect amounts due to us from the power purchaser could be impacted. Any potential taxes owed by the Manaus and Rio Negro project companies are also guaranteed by the purchaser’s parent. Based on our assessment, we have not established any accruals for this matter.
     The ultimate resolution of the matters discussed above is unknown at this time, and adverse developments related to either our ability to collect amounts due to us or related to these disputes and claims could require us to record additional losses in the future.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The information contained in Item 2 updates, and should be read in conjunction with, information disclosed in our 2010 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.
Overview and Outlook
     During the first sixnine months of 2011, our Segment EBIT was $1,011$830 million, compared with $1,400$1,913 million for the same period in 2010. Pipeline Segment EBIT year-to-dateAlthough we continued to benefit from expansion projects placed in service in 2010 and 2011, Pipeline Segment EBIT in 2011 was significantly impacted by a third quarter non-cash loss of approximately $475 million based on the difference between the net carrying value of Ruby and from the allowance for funds used during construction (AFUDC) related primarily toestimated fair value of our investment in Ruby. We also recorded a non-cash loss of approximately $125 million upon deconsolidation associated with the recognition of the accumulated other comprehensive loss associated with interest rate swaps on the Ruby pipeline project and several expansion projects not yet in service, partially offset by lower reservation revenues on our EPNG system.debt. Our Exploration and Production segment increased production volumes year over year; however, Segment EBIT year-to-date decreased by approximately $274$352 million largely due to the mark-to-market impacts of our financial derivatives despite increases in production volumes year over year. Also impacting ourand a third quarter non-cash Brazilian ceiling test charge of approximately $152 million. Our results during these periods were approximately $68also significantly impacted by $169 million in debt extinguishment losses associated with the repurchase of approximately $350 million$1.0 billion of our debt in 2011 and a gain of approximately $80 million in the second quarter of 2010 related to the sale of our Mexican pipeline and compression assets. Our quarterly results are discussed further in the individual segment results that follow.
     We continue to work towards completion of ourhave now completed what was an $8 billion backlog of pipeline expansion projects, and as of June 30,the largest in our company’s history. During 2011, the Florida Gas Transmission (FGT) Phase VIII Expansion, Phases I and II of the SNG South System III Expansion, and Phase II of the SNG Southeast Supply Header, the Gulf LNG Clean Energy and the TGP 300 Line projects were placed in service on time and on budget. In July 2011, we placed our Ruby pipeline project was also placed in service four months later than planned due to permitting and weather delays and approximately $0.65$0.7 billion over the original $3.0 billion budget. In our exploration and production business, our continued 2011 capital focus is in our Haynesville, Altamont, Eagle Ford, and Wolfcamp areas have provided us with greater exposure to both oil and natural gas liquids opportunities.areas. Finally, in our midstream business, we continue to seek out opportunities that focus on synergies with our pipeline and/or exploration and production businesses, funding these projects in a manner that is consistent with our long-term goal of improving our balance sheet.businesses. For the remainder of 2011, we expect that our pipeline and exploration and production operations will provide a strong base of earnings and operating cash flow.
     On May 24, 2011, we announced that our Board of Directors had granted initial approval of a plan to separate the Company into two publicly traded businesses by the end of 2011. The plan calls for a tax-free spin-off of our exploration and production business and related activities into a new publicly traded company separate from El Paso Corporation. The planned separation is subject to market, regulatory, tax and final approval by our Board of Directors and other customary conditions.
From a liquidity perspective, as of JuneSeptember 30, 2011 we had approximately $2.7$1.5 billion of available liquidity (exclusive of cash and credit facility capacity of EPB and Ruby)EPB). During the first sixnine months of 2011 we generated operating cash flow of approximately $1.0 billion and spent approximately $2.0 billion primarily in our capital programs. During the first half of 2011, we (i) refinanced approximately $2.25 billion of our revolving credit facilities (excluding the $1.0 billion EPPOC revolving credit facility also refinanced in May 2011) to extend these maturities to 2016 and (ii) we received approximately $1.4 billion in cash in conjunction with contributing additional ownership interests in SNG and CIG to our MLP, which funded the acquisitions primarily through the issuance of common units and debt. AsAdditionally during the first nine months of June 30, 2011, among other debt repurchase and financing activities, we refinanced approximately $2.25 billion of our remaining 2011 capital expenditures are approximately $1.6revolving credit facilities (excluding the $1.0 billion and our remaining 2011 debt maturities are approximately $0.4 billion, which we will repay as they mature. Additionally,EPPOC revolving credit facility also refinanced in May 2011). In July 2011, our unsecured $500 million unsecured credit facility matured. As further described inLiquidity and Capital Resources,we believe we are well positioned infor the remainder of 2011 to meet our obligations as well as continue with our efforts to strengthen our balance sheet. We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements and to address any changes in the financial and commodity markets and our businesses.obligations.
     As part of the plan to separate the Company into two publicly traded businesses by the end ofOn October 16, 2011, we planannounced a definitive agreement whereby KMI will acquire El Paso in a transaction that values El Paso at approximately $38 billion which includes the assumption of debt. KMI has announced that they intend to havesell our exploration and production assets and as such, we will no longer pursue the tax-free spin-off of our exploration and production business issueinto a new publicly traded company.
     Upon the merger, El Paso shareholders will receive a combination of Class P shares of common stock of KMI, common stock purchase warrants of KMI and cash. Each share of El Paso common stock (excluding any shares held by KMI and its subsidiaries or by El Paso and dissenting shares in accordance with Delaware law), will, at the effective time of the merger, be converted into the right to receive, at the election of the holder but subject to pro-ration with respect to the stock and cash portion such that approximately $2.0 billion57% of the aggregate merger consideration (excluding the warrants) is paid in cash and approximately 43% (excluding the warrants) is paid in Class P common stock of KMI, par value $0.01 per share (the “KMI Class P Common Stock”): (i) 0.9635 of a share of KMI Class P Common Stock and 0.640 of a common stock purchase warrant of KMI (a “KMI Warrant”), (ii) $25.91 in cash without interest and 0.640 of a KMI Warrant or (iii) 0.4187 of a share of KMI Class P Common Stock, $14.65 in cash without interest and 0.640 of a KMI Warrant. Each KMI Warrant will entitle its holder to $2.25 billionpurchase one share of debt,KMI Class P Common Stock at an exercise price of $40.00 per share, subject to certain adjustments, at any time during the net proceeds from which will be used to repay revolver borrowings, satisfy intercompany debt and pay a dividend to El Paso. We expect to use such proceeds as partfive-year period following the closing of the merger.

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The transactions have been approved by each of our ongoing liability management program.and KMI’s board of directors. The completion of the transactions is subject to satisfaction or waiver of certain closing conditions including, among others, customary regulatory approvals, approval of the transactions by our stockholders and approval of the issuance of KMI stock and warrants by KMI’s stockholders. A voting agreement has been executed by certain stockholders of KMI, holding approximately 75% of the voting power of KMI, in which such stockholders have agreed to vote in favor of the merger and the issuance of KMI stock and warrants. The completion of the merger will constitute a change of control for El Paso Corporation that may trigger change in control provisions in certain agreements (e.g. debt) to which we are a party.
     Additional information regarding the proposed transactions and the terms and conditions of the merger agreement, voting agreement and other related agreements is set forth in our Current Report on Form 8-K, filed on October 17, 2011.

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Segment Results
     As of JuneSeptember 30, 2011, our business consists of the following segments: Pipelines, Exploration and Production, and Marketing. We also have other business and corporate activities that include midstream and other miscellaneous businesses. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies.
     Beginning January 1, 2011, we use segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business segments. We believe Segment EBIT is useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. Segment EBIT is defined as net income (loss) adjusted for interest and debt expense and income taxes. It does not reflect a reduction for any amounts attributable to noncontrolling interests. Segment EBIT may not be comparable to measurements used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows. Our 2010 amounts have been conformed to reflect our current performance measure.
     Below is a reconciliation of our Segment EBIT to our consolidated net income (loss) for the quarters and sixnine months ended JuneSeptember 30:
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Segment
  
Pipelines $428 $472 $927 $924  $(209) $375 $718 $1,299 
Exploration and Production 250 103 219 493  183 261 402 754 
Marketing  (21)  (49)  (35)  (32)  (10)  (12)  (45)  (44)
Other  (41) 26  (100) 15   (145)  (111)  (245)  (96)
                  
Segment EBIT 616 552 1,011 1,400   (181) 513 830 1,913 
Interest and debt expense  (239)  (284)  (479)  (527)  (242)  (255)  (721)  (782)
Income tax expense  (38)  (82)  (57)  (268)
Income tax benefit (expense) 130  (75) 73  (343)
                  
Net income 339 186 475 605 
Net income (loss)  (293) 183 182 788 
Net income attributable to noncontrolling interests  (77)  (29)  (151)  (60)  (75)  (41)  (226)  (101)
                  
Net income attributable to El Paso Corporation $262 $157 $324 $545 
Net income (loss) attributable to El Paso Corporation $(368) $142 $(44) $687 
                  

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Pipelines Segment
     Overview and Operating Results.Our Pipelines Segment EBIT for the quarter and sixnine months ended JuneSeptember 30, 2011 benefited primarily from (i) several expansion projects placed in service in 2010 and 2011; (ii)2011, an increase in AFUDC on pipeline expansion projects that were not yetprior to them being placed in service during the quarter, principally the Ruby pipeline project; (iii)and higher rates on our TGP system effective June 1, 2011 due to its November 2010 rate case; and (iv) higher operating revenues due to BG LNG Services LLC’s (BG) election not to continue with Phase B of SLNG’s Elba Expansion III project. Partiallycase. More than offsetting these factors was a declineitems were non-cash losses associated with the deconsolidation of Ruby in revenues from our EPNG system due to lower demand and firm transportation commitments inthe third quarter of 2011 and an $80 milliona gain on the sale of our Mexican pipeline and compression assets in 2010. Below areListed below is a further discussion of these items, the operating results for our Pipelines segment as well as a discussion of other factors impacting Segment EBIT for the quarters and sixnine months ended JuneSeptember 30, 2011 compared with the same periods in 2010, or that could potentially impact Segment EBIT in future periods.
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions, except for volumes)  (In millions, except for volumes) 
Operating revenues $722 $680 $1,475 $1,417  $760 $692 $2,235 $2,109 
Operating expenses(1)  (397)  (370)  (775)  (726)  (1,014)  (402)  (1,789)  (1,128)
                  
Operating income 325 310 700 691 
Operating income (loss)  (254) 290 446 981 
Other income, net 103 162 227 233  45 85 272 318 
                  
Segment EBIT $428 $472 $927 $924  $(209) $375 $718 $1,299 
                  
Throughput volumes (BBtu/d)(2)(3)
 17,042 17,150 17,549 17,968  18,511 17,235 18,086 17,971 
                  
 
(1)Includes losses associated with the deconsolidation of Ruby for the quarter and nine months ended September 30, 2011.
(2) Throughput volumes include our proportionate share of unconsolidated affiliates and exclude intrasegment activities.
 
(2)(3) Throughput volumes for the quarter and sixnine months ended JuneSeptember 30, 2010 include 746 BBtu/d and 744 BBtu/d related to our Mexican pipeline assets which were sold in 2010.
                                                                
 Quarter Ended June 30, 2011 Six Months Ended June 30, 2011  Quarter Ended September 30, 2011 Nine Months Ended September 30, 2011 
 Variance Variance  Variance Variance 
 Operating Operating Operating Operating      Operating Operating Operating Operating     
 Revenue Expense Other Total Revenue Expense Other Total  Revenue Expense Other Total Revenue Expense Other Total 
 Favorable/(Unfavorable)  Favorable/(Unfavorable) 
 (In millions)  (In millions) 
Expansions $21 $(5) $21 $37 $62 $(14) $70 $118  $53 $(23) $(36) $(6) $115 $(37) $34 $112 
Reservation and usage revenues 11  (4) — 7  (15)  (7) —  (22)
Reservation/ usage revenues and expenses 56  (4) — 52 41  (11) — 30 
Gas not used in operations and revaluations  (7) — —  (7) —  (1) —  (1)  (38) 4 —  (34)  (38) 3 —  (35)
Operating and general and administrative expense —  (18) —  (18) —  (34) —  (34) —  (4) —  (4) —  (38) —  (38)
Asset sale/write down — —  (80)  (80) — 10  (80)  (70)
Project cancellation payment 17 (3)  —   14  17 (3)  —   14 
Loss on deconsolidation of Ruby —  (600) —  (600) —  (600) —  (600)
Asset sale/write downs — 21 — 21 — 31  (80)  (49)
Other(1)
 — 3 — 3 (6) — 4 (2)  (3)  (6)  (4)  (13) 8  (9) —  (1)
                                  
Total impact on Segment EBIT $42 $(27) $(59) $(44) $58 $(49) $(6) $3  $68 $(612) $(40) $(584) $126 $(661) $(46) $(581)
                                  
 
(1) Consists of individually insignificant items on several of our pipeline systems.
     Expansions.During 2011, we benefited from increased reservation revenues due to placing a number of expansion projects in service in 2010 and 2011, including (i) the (i) WIC System Expansion; (ii) Phase A of both the SLNG Elba Expansion III and Elba Express Pipeline Expansion projects; (iii) CIG Raton 2010 Expansion; (iv) Phases I and II of the SNG South System III Expansion; (v) the FGT Phase VIII Expansion and (v) Phase II of(vi) the Southeast Supply HeaderRuby pipeline project. In October 2011, the Gulf LNG Clean Energy project was placed in service and in November 2011, the TGP 300 Line expansion project was also placed in service.
     We capitalize a carrying cost (AFUDC) on funds related to our construction of long-lived assets. During the quarter and sixended September 30, 2011, our other income declined by approximately $36 million as compared to the same period in 2010 primarily due to Ruby ceasing to record AFUDC in June 2011 based on an amendment of the Ruby FERC certificate which limited AFUDC accruals. Our Pipelines Segment EBIT for the nine months ended JuneSeptember 30, 2011 we benefited from an increase in other income of approximately $21$34 million and $70 millionas compared to the same period in 2010 associated with the equity portion of AFUDC, on our expansion projects. This increase is primarily due toon our Ruby pipeline project. In April 2011, Ruby filed an amendment of its certificate requesting an increase in maximum initial recourse rates to reflect the new estimate of expected construction costs and limiting totalTGP 300 Line projects, offset by AFUDC accruals to the total amounts included in the original certificate order. In June 2011, Ruby ceased recording AFUDC basedrecorded on the proposed amendment of the certificate which was subsequently approved by the FERC in July 2011. Accordingly, our AFUDC will decline in future periods.
     In July 2011, our Ruby pipeline project wasprojects placed in service. We currently consolidate Ruby in our financial statements and reflect 100 percent of the capital cost on our balance sheet. Once certain remaining customary conditions of our partner and lenders are satisfied or waived, we will deconsolidate Ruby. We anticipate receiving these consents or waivers within 60 to 90 days after Ruby’s in service date of July 28, 2011. Upon deconsolidation, we will present Ruby in our financial statements as an equity method investment and will be required to assess the impairment of our equity investment at fair value, which is a different model than we currently use while consolidated. Currently, we assess recoverability of the Ruby pipeline project based on estimated undiscounted cash flows. As a result of assuming construction and cost overrun risk with the project, we anticipate that we will be required to record a non-cash loss on our investment in Ruby upon deconsolidation in an amount ranging from $300 million to $500 million based on our assessment of the estimated fair value of our investment in Ruby. The ultimate loss will be based on a number of factors, including actual market conditions at that time.during 2010.

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     We expect our Segment EBIT contribution from Ruby will decline in the second half of 2011 once we no longer record AFUDC incomeReservation/Usage Revenues and upon deconsolidation, begin reflecting equity earnings in Segment EBIT after reductions for interest expense and the preferred return to our partner. Our level of earnings ultimately will depend on the level of contracted customer capacity and our ability to market unsubscribed firm capacity. Approximately 1.1 Bcf/d of the total design capacity of 1.5 Bcf/d is currently subscribed. Based on current market conditions, we do not expect significant additional long-term firm capacity subscriptions in the near term.
     For additional information on our Ruby pipeline project, see Item 1, Financial Statements, Notes 10 and 12.
Reservation and Usage RevenuesExpenses.. Our reservation and usage revenues on each of our systems for the quarter and sixnine months ended JuneSeptember 30, 2011 were impacted by a number of factors, including regulatory action,actions, competition, weather and changes in supply and demand. On our TGP system, revenues increased by $18 million and $16 million fordemand, the quarter and six months ended June 30, 2011 due to higher ratesmore significant of which became effective June 1, 2011 as a result of its November 2010 rate case. The decline of $3 million and $24 million for the quarter and six months ended June 30, 2011 on our EPNG system was primarily driven by high gas storage levels and increased hydroelectric generation in its California market, the nonrenewal of certain expiring contracts and the sale of open capacity at lower prices due to lower basis differentials. On our SNG system, nonrenewal of contracts decreased our Segment EBIT by $2 million and $4 million during the quarter and six months ended June 30, 2011 compared to the same periods in 2010. Additionally, our SNG usage revenues were lower by $1 million and $4 million primarily due to record weather conditions in the Southeast during 2010 as compared to 2011.are noted below:
•TGP.Revenues increased by $50 million and $69 million for the quarter and nine months ended September 30, 2011 compared to the same periods in 2010 primarily due to higher rates which became effective June 1, 2011 as a result of its November 2010 rate case that is further discussed below. This increase was partially offset by lower revenues from gas not used in operations.
•EPNG.Reservation and usage revenues increased by approximately $10 million for the quarter ended September 30, 2011 and decreased by $12 million for the nine months ended September 30, 2011 compared to the same periods in 2010. Effective April 1, 2011, EPNG experienced higher rates as a result of its September 2010 rate case. However, EPNG also experienced reduced demand due to high gas storage levels and increased hydroelectric generation in EPNG’s California market, the nonrenewal of certain expiring contracts, the sale of open capacity at lower prices due to lower basis differentials and lower revenues related to certain interruptible services.
•SNG.Nonrenewal of expiring contracts decreased Segment EBIT by $3 million and $7 million during the quarter and nine months ended September 30, 2011 compared to the same periods in 2010. Additionally, SNG’s usage revenues were lower by $1 million and $5 million primarily due to unfavorable market conditions during 2011 as compared to 2010.
•WIC/CIG.Higher transportation expenses on our WIC and CIG systems of $4 million and $10 million for the quarter and nine months ended September 30, 2011 negatively impacted 2011 results when compared to the same periods in 2010 due to increased third party capacity commitments.
     Gas Not Used in Operations and Other Natural Gas SalesRevaluations.. GasPrior to June 1, 2011, gas not used in operations resultson our TGP system resulted in revenues to us, which we recognizerecognized when the volumes arewere retained, valued at the market price specified in our tariff. During the quarter ended June 30, 2011, our Segment EBIT, primarily on our TGP system, was favorably impacted by $4 million due to higher sales prices realized on operational gas sales, offset by the impact ofwe experienced lower retained fuel volumes in excess of fuel used in operations of $11 million. The decrease in volumes not used in operations was primarily duewhich unfavorably impacted our Segment EBIT by $40 million during the nine months ended September 30, 2011 compared to the implementationsame period in 2010. Partially offsetting the effect of this unfavorable item was $4 million of lower electric compression expenses from decreased utilization and $4 million of natural gas processing revenues recognized during the nine months ended September 30, 2011. Effective June 1, 2011, TGP implemented a fuel volume tracker effective June 1, 2011 as part of TGP’sits rate case filed with the FERC. OurFERC and as a result, no longer recognizes revenue associated with gas not used in operations which lowered Segment EBIT forby $41 million during the six monthsquarter ended JuneSeptember 30, 2011 was primarily unchanged by the impact of operational gas sales and fuel volumes in excess of fuel used in operations compared to the same period in 2010. The impact of lower retained volumes for the six months ended June 30, 2011 was offset by higher realized prices on increased operational sales volumes. The financialunfavorable impacts to our Segment EBIT associated with these operational activities on our TGP system will be largely eliminated as a result of the tracker.are offset by higher reservation revenues discussed above.
     Operating and General and Administrative Expenses. During the quarter and sixnine months ended JuneSeptember 30, 2011, our operating and general and administrative expenses were higher compared to the same periods in 2010 primarily due to higher benefits, payroll, and contractor costs of $7$17 million and $28$39 million. Additionally, our Segment EBIT was unfavorably impacted by $6 million anddue to higher property tax assessments on several of $5 millionour pipeline systems during the nine months ended September 30, 2011. Partially offsetting these unfavorable impacts were lower corporate overhead allocations and $7 milliona favorable franchise tax settlement on our TGP system.system which combined reduced operating expenses by $10 million and $12 million for the quarter and nine months ended September 30, 2011.
Loss on Deconsolidation of Ruby.In September 2011, upon meeting certain conditions of our partner and the lenders, we deconsolidated Ruby and began reflecting it as an investment in an unconsolidated affiliate. Subsequent to deconsolidation, Ruby’s income (loss) is reflected in earnings from unconsolidated affiliates on our income statement and is included in Pipeline Segment EBIT. Earnings from unconsolidated affiliates is after interest, taxes and the preferred return of our partner. As a result of the deconsolidation of Ruby, we recorded a third quarter non-cash loss of approximately $475 million based on the difference between the net carrying value of Ruby and the estimated fair value of our investment in Ruby. We also recorded a non-cash loss of approximately $125 million related to the recognition of the accumulated other comprehensive loss associated with interest rate swaps on the Ruby debt. Subsequent to deconsolidation, Ruby’s interest rate swaps continue to hedge Ruby’s project level debt. For additional information on our Ruby pipeline project, see Item 1, Financial Statements, Note 15.
     Asset Sale/Write DownDowns. During 2010, our Pipelines Segment EBIT was impacted by the secondfollowing asset write-downs and sale: (i) a $21 million non-cash asset write-down in the third quarter based on a FERC order related to the sale of 2010, we recordedthe Natural Buttes compressor station and gas processing plant in 2009; (ii) an impairment of approximately $10 million in the first quarter primarily related to a decision not to continue with a storage project due to market conditions; and (iii) a third quarter gain of approximately $80 million on the sale of our interests in certain Mexican pipeline and compression assets. In addition, during the first quarter of 2010, we recorded an impairment of approximately $10 million primarily related to our decision not to continue with a storage project due to market conditions.

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Project Cancellation Payment.During the quarter and six months ended June 30, 2011, we recognized operating revenues of $17 million related to BG’s election not to continue with Phase B of our SLNG Elba Expansion III project, partially offset by $3 million for certain project development costs incurred in conjunction with this expansion project which were written off.
     Other Regulatory Matters.Our pipeline systems periodically file for changes in their rates, which are subject to approval by the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, several of our pipelines have projected upcoming rate actions with anticipated effective dates through 2013 as further described below.
     EPNG Rate Case. In September 2010, EPNG filed a new rate case with the FERC proposing an increase in its base tariff rates which would increase revenue by approximately $100 million annually over previously effective tariff rates. It is uncertain whether such an increase will be achieved in the context of any settlement between EPNG and its customers or following the outcome of a hearing in the rate case. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. A hearing commenced in late October 2011. It is uncertain whether the requested increase will be achieved in the context of any settlement between EPNG and its customers or following the outcome of a hearing in the rate case. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.
     TGP Rate Case.In November 2010, TGP filed a rate case with the FERC proposing an increase in its base tariff rates of approximately $200 million annually over previously effective tariff rates. It is uncertain whether such an increase will be achieved inand the context of any settlement between TGP and its customers or following the outcomeimplementation of a hearingfuel volume tracker with a reduction in the rate case.TGP’s fuel retention rates, among other things. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. In September 2011, TGP filed a proposed settlement with the FERC, which was uncontested by its customers. The proposed settlement provides for, among other things, an increase in TGP’s revenues of approximately $60 million to $70 million annually, net of revenues from excess fuel retention, significant contract extensions until October 2014 and a requirement to file new rates to be effective no earlier than April 2014 but no later than November 2015. Although the final outcome isFERC has not currently determinable,yet approved the proposed settlement, we believe our accruals established for this matter are adequate.
     CIG Rate Case.In MayAugust 2011, CIG reached athe FERC approved an uncontested pre-filing settlement with all of its shippers of a rate case required under the terms of aCIG’s previous settlement. CIG has filed the proposedThe settlement with the FERC whichgenerally provides for CIG’s current tariff rates to continue until its next general rate case which will be effective after October 1, 2014 but no later than October 1, 2016. At this time, the FERC has not ruled on that petition and the outcome of this matter is not determinable.

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Exploration and Production Segment
Overview and Strategy
     Our Exploration and Production segment conducts our oil and natural gas exploration and production activities. The success of this segment is driven by the ability to locate and develop economic oil and natural gas reserves and extract those reserves at the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management. Our strategy focuses on building and applying competencies in assets with repeatable programs, executing to improve capital and expense efficiency, and maximizing returns by adding assets and inventory that match our competencies and divesting assets that do not. During 2011, we sold non-core oil and natural gas properties located in our Central, Western and Southern divisions in several transactions from which we received proceeds that totaled approximately $570 million. For a further discussion of our business strategy in our exploration and production business, see our 2010 Annual Report on Form 10-K.
     Our profitability and performance is impacted by, among other factors, changes in commodity prices and industry-wide changes in the cost of drilling and oilfield services which impact our daily production, operating and capital costs. We may also be impacted by the effect of hurricanes and other weather events, or the effects of domestic or international regulatory or other actions in response to events outside of our control (e.g. oil spills). To the extent possible, we attempt to mitigate certain of these risks through actions, such as entering into contractual arrangements to control costs and entering into derivative contracts to reduce the financial impact of downward commodity price movements.
     In May 2011, we announced that our Board of Directors had granted initial approval to spin-off the exploration and production business into a new publicly traded company separate from El Paso Corporation by the end of 2011. The spin-off is subject to market, regulatory, tax and final approval by our Board of Directors and other customary conditions.
Significant Operational Factors Affecting the Periods Ended JuneSeptember 30, 2011 and 2010
     Volumes.Our volumes by commodity for the sixnine months ended JuneSeptember 30 were as follows:
                
 2011 2010  2011 2010 
Natural Gas (MMcf/d)  
Consolidated volumes 658 622  656 615 
Unconsolidated affiliate volumes 47 46  46 47 
          
Total Combined 705 668  702 662 
          
Oil and condensate (MBbls/d)  
Consolidated volumes 14 13  15 13 
Unconsolidated affiliate volumes 1 1  1 1 
          
Total Combined 15 14  16 14 
          
NGL (MBbls/d)  
Consolidated volumes 3 4  3 4 
Unconsolidated affiliate volumes 2 2  2 2 
          
Total Combined 5 6  5 6 
          
Equivalent Volumes (MMcfe/d) 
Consolidated volumes 762 715 
Unconsolidated affiliate volumes 61 62 
     
Total Combined 823 777 
     

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     Our average daily production volumes for the sixnine months ended JuneSeptember 30, 2011 was 822were 823 MMcfe/d, including 6261 MMcfe/d from our equity interest in the production of Four Star. Below is an analysis of our production by division for the six monthsperiods ended JuneSeptember 30:
                
 2011 2010  2011 2010 
 MMcfe/d  MMcfe/d 
United States  
Central 415 330  414 328 
Western 154 156  155 159 
Southern (1)
 157 205  160 196 
International  
Brazil 34 31  33 32 
          
Total Consolidated 760 722  762 715 
Unconsolidated affiliate 62 62  61 62 
          
Total Combined 822 784  823 777 
          
 
(1) In 2011, our Gulf Coast division was renamed the Southern division, and we made minor changes to the properties contained within our various domestic operating divisions. Divisional amounts for prior periods have been adjusted to reflect these changes.
     Central division— Our 2011 Central division production volumes continued to increase as a result of our successful drilling programs in the Haynesville shale. At JuneAs of September 30, 2011, we had 8391 operated wells and our total production was approximately 260257 MMcfe/d related to our Haynesville program. In addition, in south Louisiana we are developing our emerging Wilcox program. This is a relatively new oil play we have added to our drilling program. As of September 30, 2011, we had eight operated wells related to our Wilcox program.
     Western division— Our 2011 Western division production volumes are roughly flat compared to 2010 due to natural declines in the Rockies and County Line programs offset by increased production volumes in Altamont.our Altamont and Raton programs. As of JuneSeptember 30, 2011 we had 251254 operated wells and our total oil production was approximately 51 MMcfe/7 MBbls/d related to our Altamont program.
     Southern division— Our 2011 Southern division production volumes decreased primarily due to natural declines and lower levels of drilling activity in the Texas Gulf Coast and Gulf of Mexico areas. In this division, we continue to focus on increasing our Eagle Ford shale activity, where in 2011 we have successfully drilled 2837 additional wells, for a total of 4857 wells. These wells are located principally in the liquids rich area of the Eagle Ford shale. As of JuneSeptember 30, 2011, our total oil and NGL production at Eagle Ford was approximately 37 MMcfe/7 MBbls/d, related to our Eagle Ford program. Additional Eagle Fordand additional production is currentlywas constrained due to infrastructure limitations which we expect will be resolved inlimited natural gas takeaway capacity. Subsequent to September 30, 2011, upon the second halfcompletion of 2011.a natural gas gathering system, our oil and NGL production has increased to approximately 10 MBbls/d. We also continue to assess our Wolfcamp shale area, having drilled seven12 wells during 2011.
     International— Our 2011 production volumes in Brazil increased due to production from our Camarupim Field. We continue to work with the operator, Petrobras, in this field where aA fourth well is expected to beginin the field began production later induring the third quarter of 2011. We also continueDuring the process of obtaining regulatory andquarter ended September 30, 2011, we were informed that our environmental approvalspermit request for the Pinauna Field in the Camamu Basin thatwas denied. As a result, we released $94 million of unevaluated capitalized costs related to this field into the Brazilian full cost pool. We have filed an appeal and are required in order to enter the next phase of development. Duringawaiting a response. Additionally, during the quarter and nine months ended JuneSeptember 30, 2011, we released $44approximately $42 million and $86 million, respectively, of our unevaluated capitalized costs related to the ES-5 block to our Brazilian full cost pool upon the completion of our evaluation of an exploratory wellwells drilled in 2009. As of June 30, 2011, we have approximately $142 million2009 and $70 million of remaining unevaluated capitalized costs2010 without any additions to our proved reserves. We will continue to pursue alternatives for the hydrocarbons discovered in Brazil andthese areas. In Egypt, respectively. Duringduring the second halfremainder of the year we expect to complete a test of an exploratory well drilled in 2010 in Brazil and furthercontinue to evaluate the commerciality of areas within our South Alamein and South Mariut blocksblocks.
     As a result of the developments in Brazil, we recorded a non-cash ceiling test charge of approximately $152 million in our Brazilian full cost pool for the quarter and nine months ended September 30, 2011. We may incur additional ceiling test charges in Brazil in the future depending on the value of our proved reserves, which are subject to change as a result of factors such as prices, costs and well performance. Additionally, we may incur ceiling test charges in Egypt through the drilling of additional wells. Dependingdepending on the results of our drilling activities in that country. At September 30, 2011, we could incur ceiling test chargeshave total oil and natural gas capitalized costs of approximately $207 million and $71 million in the future.Brazil and Egypt, of which $8 million and $71 million are unevaluated capitalized costs.

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     Cash Operating Costs.We monitor cash operating costs required to produce our oil and natural gas production volumes. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses less depreciation, depletion and amortization expense, ceiling test and other impairment charges, transportation costs and cost of products. Cash operating costs per unit is a valuable measure of operating performance and efficiency for our Exploration and Production segment, however, this measure may not be comparable to those used by other companies. During the sixnine months ended JuneSeptember 30, 2011, cash operating costs per unit decreasedincreased to $1.80/Mcfe as compared to $1.83/$1.76/Mcfe during the same period in 2010.2010 due to increased lease operating expenses.
     Capital Expenditures.Our total oil and natural gas capital expenditures were $736$1,183 million for the sixnine months ended JuneSeptember 30, 2011, of which $724$1,158 million were domestic capital expenditures.

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Capital expenditures for the sixnine months ended JuneSeptember 30, 2011 and rig count by core program as of JuneSeptember 30, 2011 were:
        
         Capital   
 Capital Expenditures    Expenditures   
 (In millions) Rig Count  (In millions) Rig Count 
Haynesville $197 4  $319 4 
Altamont 74 3  120 2 
Eagle Ford 275 4  443 3 
Wolfcamp 70 2  115 2 
Other programs 120 1 
Other, including International 186 2 
          
Total capital expenditures $736 14  $1,183 13 
          
Outlook for 2011
     For the full year we currently expect the following on a worldwide basis:
Capital expenditures, excluding acquisitions, of approximately $1.6 billion. Of this total, we expect to spend approximately $1.5 billion on our domestic program (more than half of which is expected to be allocated to oil and liquids programs) and approximately $0.1 billion in Brazil and Egypt.
Average daily equivalent total production volumes for the year of approximately 830 MMcfe/d to 860 MMcfe/d, which includes approximately 60 MMcfe/d from Four Star.
Average daily oil production volumes for the year of approximately 18.5 MBbls/d to 20.5 MBbls/d, including Four Star.
Average cash operating costs between $1.70/Mcfe and $1.85/Mcfe for the year; and
Depreciation, depletion and amortization rate between $2.05/Mcfe and $2.15/Mcfe.
•Capital expenditures, excluding acquisitions, of approximately $1.6 billion, approximately 60 percent of which is expected to be allocated to oil and liquids programs.
•Average daily total production volumes for the year of approximately 830 MMcfe/d to 840 MMcfe/d, which includes approximately 60 MMcfe/d from Four Star.
•Average daily oil production volumes for the year of approximately 16.5 MBbls/d to 18.5 MBbls/d, including Four Star.
•Average cash operating costs between $1.70/Mcfe and $1.85/Mcfe for the year; and
•Depreciation, depletion and amortization rate between $2.10/Mcfe and $2.15/Mcfe.
Price Risk Management Activities
     We enter into derivative contracts on our oil and natural gas production to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. Because we apply mark-to-market accounting on our financial derivative contracts and because we do not hedge all of our price risks, this strategy only partially reduces our commodity price exposure. Our reported results of operations, financial position and cash flows can be impacted significantly by commodity price movements from period to period. Adjustments to our strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company. During the first sixnine months of 2011, approximately 8682 percent of our natural gas production and 100 percent of our crude oil production were economically hedged at average floor prices of $5.71$5.76 per MMBtu and $85.99 per barrel, respectively.

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     The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under our outstanding derivative contracts as of JuneSeptember 30, 2011.
                                                
 2011 2012 2013  2011 2012 2013 
 Average Average Average  Average Average Average 
 Volumes(1) Price(1) Volumes(1) Price(1) Volumes(1) Price(1)  Volumes(1) Price(1) Volumes(1) Price(1) Volumes(1) Price(1) 
Natural Gas
  
Fixed Price Swaps 86 $5.87 105 $6.01 — $—  39 $6.07 105 $6.01 — $— 
Ceilings 9 $7.29 — $— — $—  5 $7.29 — $— — $— 
Floors 9 $6.00 — $— — $—  5 $6.00 — $— — $— 
Basis Swaps(2)
  
Texas Gulf Coast 17 $(0.13) — $— — $—  8 $(0.13) — $— — $— 
Raton 11 $(0.25) — $— — $—  6 $(0.25) — $— — $— 
Oil
  
Fixed Price Swaps 1,012 $87.54 640 $100.13 — $—  506 $87.54 640 $100.13 — $— 
Ceilings — $— 1,464 $95.00 2,920 $96.88  — $— 1,464 $95.00 2,920 $96.88 
Three Way Collars — Ceiling 1,840 $94.27 5,764 $114.16 1,552 $128.34  920 $94.27 5,764 $114.16 1,552 $128.34 
Three Way Collars — Floors(3)
 1,840 $85.14 5,764 $92.54 1,552 $100.00  920 $85.14 5,764 $92.54 1,552 $100.00 
 
(1) Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.
 
(2) Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences.
 
(3) If market prices settle at or below $65.00, $67.54 and $75.00 for the years 2011, 2012 and 2013, respectively, our three way collars-floors effectively “lock-in” a cash settlement of $20.14 per Bbl for 2011 and $25.00 per Bbl for 2012 and 2013 above that market price.2013.
Operating Results and Variance Analysis
     The information below provides the financial results and an analysis of significant variances in these results during the quarters and sixnine months ended JuneSeptember 30:
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Physical sales
  
Natural gas $257 $228 $497 $516  $256 $239 $753 $755 
Oil and condensate 133 89 236 164  131 83 367 247 
NGL 13 16 28 34  15 12 43 46 
                  
Total physical sales 403 333 761 714  402 334 1,163 1,048 
                  
Realized and unrealized gains on financial derivatives 132 31 23 284  251 184 274 468 
Other revenues — 5 1 18  — 1 1 19 
                  
Total operating revenues 535 369 785 1,016  653 519 1,438 1,535 
                  
Operating expenses
  
Cost of products — 5 — 15  — — — 15 
Transportation costs 18 18 38 36  20 18 58 54 
Production costs 70 64 143 133  80 61 223 194 
Depreciation, depletion and amortization 146 128 280 235  157 117 437 352 
General and administrative expenses 48 47 98 96  46 41 144 137 
Ceiling test charges — — — 2  152 14 152 16 
Other 3 5 6 9  8 3 14 12 
                  
Total operating expenses 285 267 565 526  463 254 1,028 780 
                  
Operating income 250 102 220 490  190 265 410 755 
Other (expense) income(1)
 — 1  (1) 3 
Other expense(1)
  (7)  (4)  (8)  (1)
                  
Segment EBIT $250 $103 $219 $493  $183 $261 $402 $754 
                  
 
(1) Includes equity earnings from Four Star, our unconsolidated affiliate, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets.

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     The table below provides additional detail of our volumes, prices, and costs per unit. We present (i) average realized prices based on physical sales of natural gas, oil and condensate and NGL as well as (ii) average realized prices including the impacts of financial derivative settlements. Our average realized prices, including financial derivative settlements reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur; however, these prices do not reflect the impact of any associated premiums paid to enter into certain of our derivative contracts.
                 
  Quarters Ended June 30,  Six Months Ended June 30, 
  2011  2010  2011  2010 
Volumes
                
Natural gas (MMcf)                
Consolidated volumes  59,791   56,361   119,052   112,508 
Unconsolidated affiliate volumes  4,301   4,144   8,554   8,358 
Oil and condensate (MBbls)                
Consolidated volumes  1,349   1,245   2,543   2,243 
Unconsolidated affiliate volumes  76   108   159   198 
NGL (MBbls)                
Consolidated volumes  245   387   538   791 
Unconsolidated affiliate volumes  128   123   280   279 
Equivalent volumes                
Consolidated MMcfe  69,356   66,154   137,543   130,711 
Unconsolidated affiliate MMcfe  5,526   5,529   11,186   11,219 
             
Total combined MMcfe  74,882   71,683   148,729   141,930 
             
Consolidated MMcfe/d  762   727   760   722 
Unconsolidated affiliate MMcfe/d  61   61   62   62 
             
Total combined MMcfe/d  823   788   822   784 
             
Consolidated prices and costs per unit
                
Natural gas ($/Mcf)                
Average realized price on physical sales $4.29  $4.05  $4.18  $4.59 
Average realized price, including financial derivative settlements(1)(2)
 $5.44  $5.86  $5.44  $5.95 
Average transportation costs $0.28  $0.31  $0.30  $0.30 
Oil and condensate ($/Bbl)                
Average realized price on physical sales $98.46  $71.54  $92.74  $73.08 
Average realized price, including financial derivative settlements(1)(2)
 $91.30  $71.04  $88.67  $72.03 
Average transportation costs $0.06  $0.06  $0.06  $0.06 
NGL ($/Bbl)                
Average realized price on physical sales $54.85  $40.10  $52.41  $42.43 
Average transportation costs $4.73  $2.57  $4.88  $2.68 
Production costs and other cash operating costs ($/Mcfe)                
Average lease operating expenses $0.71  $0.67  $0.73  $0.71 
Average production taxes(3)
  0.31   0.30   0.31   0.31 
             
Total production costs $1.02  $0.97  $1.04  $1.02 
Average general and administrative expenses  0.69   0.72   0.71   0.74 
Average taxes, other than production and income taxes  0.04   0.08   0.05   0.07 
             
Total cash operating costs $1.75  $1.77  $1.80  $1.83 
             
Depreciation, depletion and amortization ($/Mcfe)(4)
 $2.11  $1.92  $2.04  $1.79 
             
     The table below provides additional detail of our volumes, prices, and costs per unit. We present (i) average realized prices based on physical sales of oil and condensate, natural gas and NGL as well as (ii) average realized prices including the impacts of financial derivative settlements. Our average realized prices, including financial derivative settlements reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur; however, these prices do not reflect the impact of any associated premiums paid to enter into certain of our derivative contracts.
                 
  Quarters Ended September 30,  Nine Months Ended September 30, 
  2011  2010  2011  2010 
Volumes
                
Natural gas (MMcf)                
Consolidated volumes  59,962   55,331   179,014   167,839 
Unconsolidated affiliate volumes  4,163   4,350   12,717   12,708 
Oil and condensate (MBbls)                
Consolidated volumes  1,511   1,225   4,054   3,468 
Unconsolidated affiliate volumes  73   87   232   285 
NGL (MBbls)                
Consolidated volumes  262   315   800   1,106 
Unconsolidated affiliate volumes  142   143   422   422 
Equivalent volumes                
Consolidated MMcfe  70,598   64,575   208,141   195,286 
Unconsolidated affiliate MMcfe  5,457   5,729   16,643   16,948 
             
Total combined MMcfe  76,055   70,304   224,784   212,234 
             
Consolidated MMcfe/d  767   702   762   715 
Unconsolidated affiliate MMcfe/d  60   62   61   62 
             
Total combined MMcfe/d  827   764   823   777 
             
Consolidated prices and costs per unit
                
Natural gas ($/Mcf)                
Average realized price on physical sales $4.27  $4.31  $4.21  $4.50 
Average realized price, including financial derivative settlements(1)(2)
 $5.60  $5.93  $5.49  $5.95 
Average transportation costs $0.32  $0.30  $0.30  $0.30 
Oil and condensate ($/Bbl)                
Average realized price on physical sales $86.73  $68.00  $90.50  $71.28 
Average realized price, including financial derivative settlements(1)(2)
 $88.95  $68.51  $88.77  $70.79 
Average transportation costs $0.07  $0.10  $0.06  $0.07 
NGL ($/Bbl)                
Average realized price on physical sales $56.03  $39.21  $53.59  $41.51 
Average transportation costs $3.04  $3.56  $4.28  $2.93 
Cash operating costs ($/Mcfe)                
Average lease operating expenses $0.87  $0.70  $0.77  $0.71 
Average production taxes(3)
  0.27   0.24   0.30   0.29 
Average general and administrative expenses  0.65   0.63   0.69   0.70 
Average taxes, other than production and income taxes  0.03   0.05   0.04   0.06 
             
Total cash operating costs $1.82  $1.62  $1.80  $1.76 
             
Depreciation, depletion and amortization ($/Mcfe)(4)
 $2.22  $1.81  $2.10  $1.80 
             
 
(1) We had no cash premiums related to natural gas and oil derivatives settled during the quarter and sixnine months ended JuneSeptember 30, 2011. Premiums related to natural gas derivatives settled during the quarter and sixnine months ended JuneSeptember 30, 2010 were $48 million and $100$148 million. Had we included these premiums in our natural gas average realized prices in 2010, our realized price, including financial derivative settlements, would have decreased by $0.85/Mcf and $0.89/$0.88/Mcf for the quarter and sixnine months ended JuneSeptember 30, 2010. We had no premiums related to oil derivatives settled during the quarter and sixnine months ended JuneSeptember 30, 2010.
 
(2) The quarters ended JuneSeptember 30, 2011 and 2010, include approximately $68$80 million and $102$90 million of cash receipts for settlements of natural gas derivative contracts and approximately $9$3 million and less than $1 million of cash paidreceipts for settlements of crude oil derivative contracts. The sixnine months ended JuneSeptember 30, 2011 and 2010, include approximately $150$230 million and $153$243 million of cash receipts for settlements of natural gas derivative contracts and approximately $10$7 million and $2 million of cash paid for settlements of crude oil derivative contracts.
 
(3) Production taxes include ad valorem and severance taxes.
 
(4) Includes $0.06 per Mcfe for each of the quarters ended September 30, 2011 and 2010 and $0.06 and $0.07 per Mcfe for the quarters ended June 30, 2011 and 2010, respectively, and $0.06 per Mcfe for each of the sixnine months ended JuneSeptember 30, 2011 and 2010 related to accretion expense on asset retirement obligations.

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Quarter and SixNine Months Ended JuneSeptember 30, 2011 Compared with Quarter and SixNine Months Ended JuneSeptember 30, 2010
     Our Segment EBIT for the quarter ended June 30, 2011 increased $147 million and for the sixnine months ended JuneSeptember 30, 2011 decreased $274$78 million and $352 million as compared to the same periods in 2010. The table below shows the significant variances of our financial results for the quarter and sixnine months ended JuneSeptember 30, 2011 as compared to the same periods in 2010:
                                                                
 Quarter Ended June 30, 2011 Six Months Ended June 30, 2011  Quarter Ended September 30, 2011 Nine Months Ended September 30, 2011 
 Variance Variance  Variance Variance 
 Operating Operating Operating Operating      Operating Operating Operating Operating     
 Revenue Expense Other Segment EBIT Revenue Expense Other Segment EBIT  Revenue Expense Other Segment EBIT Revenue Expense Other Segment EBIT 
 Favorable/(Unfavorable)  Favorable/(Unfavorable) 
 (In millions)  (In millions) 
Physical sales
  
Natural gas  
Higher (lower) realized prices in 2011 $15 $— $— $15 $(49) $— $— $(49)
Lower realized prices in 2011 $(3) $— $— $(3) $(52) $— $— $(52)
Higher volumes in 2011 14 — — 14 30 — — 30  20 — — 20 50 — — 50 
Oil and condensate  
Higher realized prices in 2011 36 — — 36 50 — — 50  29 — — 29 78 — — 78 
Higher volumes in 2011 8 — — 8 22 — — 22  19 — — 19 42 — — 42 
NGL  
Higher realized prices in 2011 3 — — 3 5 — — 5  5 — — 5 10 — — 10 
Lower volumes in 2011  (6) — —  (6)  (11) — —  (11)  (2) — —  (2)  (13) — —  (13)
Realized and unrealized gains (losses) on financial derivatives
 101 — — 101  (261) — —  (261) 67 — — 67  (194) — —  (194)
Other revenues
  (5) — —  (5)  (17) — —  (17)  (1) — —  (1)  (18) — —  (18)
Depreciation, depletion and amortization expense
  
Higher depletion rate in 2011 —  (13) —  (13) —  (34) —  (34) —  (30) —  (30) —  (64) —  (64)
Higher production volumes in 2011 —  (5) —  (5) —  (11) —  (11) —  (10) —  (10) —  (21) —  (21)
Production costs
  
Higher lease operating expenses in 2011 —  (5) —  (5) —  (7) —  (7) —  (16) —  (16) —  (23) —  (23)
Higher production taxes in 2011 —  (1) —  (1) —  (3) —  (3) —  (3) —  (3) —  (6) —  (6)
General and administrative expenses
 —  (1) —  (1) —  (2) —  (2) —  (5) —  (5) —  (7) —  (7)
Ceiling test charges
 — — — — — 2 — 2  —  (138) —  (138) —  (136) —  (136)
Earnings from investment in Four Star
 — — 2 2 — — — —  — —  (1)  (1) — —  (1)  (1)
Other
 — 7  (3) 4 — 16  (4) 12  —  (7)  (2)  (9) — 9  (6) 3 
                                  
Total Variances
 $166 $(18) $(1) $147 $(231) $(39) $(4) $(274) $134 $(209) $(3) $(78) $(97) $(248) $(7) $(352)
                                  
     Physical sales.Physical sales represent accrual-based commodity sales transactions with customers. During the quarter and sixnine months ended JuneSeptember 30, 2011, our revenues increased compared to the same periods in 2010, primarily as a result of higher oil and natural gas volumes and higher oil and condensate prices. During the quarter ended June 30, 2011, our revenues also benefited from higherprices partially offset by lower natural gas prices. The higher volumes are due to our focus on our core programs in the Haynesville and Eagle Ford shales.
     Realized and unrealized gains (losses) on financial derivatives.During the quarter and sixnine months ended JuneSeptember 30, 2011, we recognized net gains of $132$251 million and $23$274 million compared to net gains of $31$184 million and $284$468 million during the same periods in 2010. Gains or losses each period are due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts.
     Depreciation, depletion and amortization expense.During the quarter and sixnine months ended JuneSeptember 30, 2011, our depreciation, depletion and amortization expense increased as a result of a higher depletion rate and higher production volumes compared with the same periods in 2010. OurWe expect our depreciation, depletion and amortization rate is higher due to our focus on more liquids rich programs and we expect the rate to continue to increase during the second halfremainder of the year.year as we focus our capital on more liquids rich programs.
Production costs.During the quarter and nine months ended September 30, 2011, our production costs increased as compared to the same periods in 2010 primarily due to higher lease operating expenses and higher production taxes primarily associated with higher volumes. Lease operating expenses increased due to higher maintenance, repair and fuel costs in our Western division, temporary higher costs in our Southern division due to infrastructure delays in the area and higher expenses in our International division.
     General and administrative expenses.During the sixnine months ended JuneSeptember 30, 2011, our general and administrative expenses increased compared to the same period in 2010, due to severance costs related to an office closure, offset by a lower corporate overhead allocation and lower labor-related costs.closure. The impact of these severance costs was approximately $5 million, or $0.04$0.02 per Mcfe on total cash operating costs.
Production costs.During the quarter and six months ended June 30, 2011, our production costs increased as compared to the same periods in 2010 primarily due to higher lease operating expenses in our Western division as a result of higher subsurface maintenance costs and higher production taxes associated with higher volumes.

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     Ceiling test charges.We are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. During the first quarter of 2010,and nine months ended September 30, 2011 we recorded a non-cash ceiling test charge of approximately $152 million in our Brazilian full cost pool. The ceiling test charge was driven by the release of costs into the Brazilian full cost pool substantially due to the recent denial of a necessary environmental permit on our Pinauna project as well as the completion of our evaluation of certain exploratory wells drilled in 2009 and 2010. We have filed an appeal with regard to the denial of the permit and are awaiting a response. During the quarter and nine months ended September 30, 2010, we recorded non-cash ceiling test charges of $14 million and $16 million in our Egyptian full cost pool of $2 million as a result of acreage relinquishments in South Mariut and South Alamein and a dry hole drilled in the relinquishment of approximately 30 percentTanta block. We may incur additional ceiling test charges in Brazil in the future depending on the value of our acreageproved reserves, which are subject to change as a result of factors such as prices, costs and well performance. Additionally, we may incur ceiling test charges in Egypt depending on the South Mariut block.results of our activities in that country.

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Marketing Segment
     Our Marketing segment’s primary focus is to market our Exploration and Production segment’s oil and natural gas production and to manage El Paso’s overall price risk. In addition, we continue to manage and liquidate certain legacy contracts. All of our remaining contracts are subject to counterparty credit and non-performance risks while our remaining mark-to-market contracts are also subject to interest rate exposure. Our contracts are described below and in further detail in our 2010 Annual Report on Form 10-K.
     Natural gas transportation-relatedtransportation contracts.The impact of these accrual-based contracts is based on our ability to use or remarket the contracted pipeline capacity and the amount of production from our Exploration and Production segment. As of JuneSeptember 30, 2011, these contracts require us to pay demand charges of $19$18 million for the remainder of 2011 and an average of $40$50 million per year between 2012 and 2015.
     Legacy natural gas and power contracts.As of JuneSeptember 30, 2011, these contracts include (i) long-term accrual basedaccrual-based supply contracts, including transportation expenses, that obligate us to deliver natural gas to specified power plants and (ii) power contracts in the PJM region through 2016, which we mark-to-market in our results. These contracts are expected to have minimal future impact on our earnings as we have entered into offsetting positions that eliminate the price risks associated with our PJM power contracts and substantially offset the fixed price exposure related to our natural gas supply contracts.
Operating Results
     Overview. Our overall operating results and analysis for our Marketing segment during each of the quarters and sixnine months ended JuneSeptember 30 are as follows:
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Income (Loss)
  
Contracts Related to Legacy Trading Operations:
  
Natural gas transportation-related contracts: 
Accrual-based contracts (including natural gas transportation): 
Demand charges $(12) $(10) $(22) $(19) $(15) $(10) $(37) $(29)
Settlements, net of termination payments  (2) 5  (3) 16  8 10  5  26 
Changes in fair value of other natural gas derivative contracts  (2)  (4)  (2)  (5) —  (3)  (2)  (8)
Changes in fair value of power contracts  (4)  (39)  (5)  (21)  (2)  (13)  (7)  (34)
                  
Total revenues  (20)  (48)  (32)  (29)  (9)  (16)  (41)  (45)
Operating expenses  (2)  (1)  (4)  (3) — 4  (4) — 
                  
Operating loss $(22) $(49) $(36) $(32) $(9) $(12) $(45) $(45)
                  
Other income, net 1 — 1 —   (1) — — 1 
                  
Segment EBIT $(21) $(49) $(35) $(32) $(10) $(12) $(45) $(44)
                  
     During the quarter2011 and six months ended June 30, 2011, our results2010, Segment EBIT losses were primarily impacted by a $7 milliondue to losses on transportation-related contracts and $22 million loss related to settlements on an affiliated fuel supply agreement. This agreement terminated in June 2011. Our results for the quarter and six months ended June 30, 2010 were primarily impacted by changes in the fair value of our legacy power contracts in the PJM region prior to the execution of additional offsetting positions. The first half of 2011 also includes a $22 million loss on the settlement of an affiliated fuel supply agreement which was terminated in June 2011 which was reflected as a component of settlements, net of termination payments, from accrual-based contracts.

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Other Activities
     Our other activities include our midstream operations, corporate general and administrative functions our midstream operations and other miscellaneous businesses.
     Midstream. As of JuneSeptember 30, 2011, our midstream operations consist primarily of wholly-owned assets in the Haynesville area in north Louisiana and the Eagle Ford area in south Texas, in addition to an equity investment in a joint venture that owns the Altamont natural gas gathering system and processing plant in the Uintah basin of Utah. The joint venture is currently working to expand the Altamont system, and we and our joint venture partner have each committed to make up to $500 million of future capital contributions to the joint venture for additional midstream projects to be acquired or developed by the joint venture. Our midstream business is also evaluating several larger scale projects in the Eagle Ford area, in the emerging shale plays in the Rockies, west Texas and the northeast United States including the Marcellus shale in Pennsylvania as further discussed below.States.
     In late JuneOn September 15, 2011, we announced anthe open season which will close on September 15, 2011,ended to elicit binding commitments from prospective shippers interested in ethane transportation on our newthe proposed Marcellus Ethane Pipeline System (MEPS) designed to provide transportation service from the West Virginia and Pennsylvania Marcellus shale supply areas to markets in Louisiana or Texas. We have entered into a Memorandum of Understanding with a wholly-owned subsidiary of Spectra Energy Corp.The MEPS project did not receive adequate commitments from the open season to pursue joint development ofproceed at this project.time.
     For the full year 2011, we expect to make capital expenditures and equity investments totaling approximately $100$90 million related to the midstream projects discussed above.
     The following is a summary of significant items impacting the Segment EBIT in our other activities for the quarters and sixnine months ended JuneSeptember 30:
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions)  (In millions) 
Income (Loss)
  
Loss on debt extinguishment $(27) $— $(68) $—  $(101) $(104) $(169) $(104)
Change in environmental, legal and other reserves  (13) 10  (24) 2   (28)  (18)  (52)  (16)
Midstream 4 3 6 3   (2) 2 4 5 
Other  (5) 13  (14) 10   (14) 9  (28) 19 
                  
Total Segment EBIT $(41) $26 $(100) $15  $(145) $(111) $(245) $(96)
                  
     Loss on Debt Extinguishment.During 2011, we incurred losses primarily related to the repurchase of approximately $350 million$1.0 billion of our senior unsecured notes. In July 2011, we repurchased an additional $274 million of debt under our early tender offer and anticipate spending up to an additional $438 million in August 2011 to buy back additional debt. In conjunction with these transactions we anticipate recording losses of approximately $100 million during the third quarter of 2011.
     Environmental, Legal and Other Reserves.We have a number of pending litigation matters and reserves related to our historical business operations that affect our results. Adverse rulings or unfavorable outcomes or settlements against us related to these matters have impacted and may continue to impact our future results. Our results for both the quarter and sixnine months ended JuneSeptember 30, 2011 and 2010 were primarily impacted by adjustments to certain legacy indemnifications and other environmental matters, primarily relatedincluding a non-operated chemical plant and a non-operated refinery in south Texas. Also impacting these results were adjustments to certain legacy indemnifications, including an indemnification on which our liability fluctuates with ammonia prices and a non-operating chemical plant.prices.
     Other.Other consists primarily ofOur results were also impacted by gains (losses) related to our legacy power assets and exposures, foreign currency fluctuations, and benefit costs associated with certain of our postretirementpost-retirement benefit plans. For more information about our postretirement benefit plans and related benefit costs, see Item 1, Financial Statements, Note 9. During both the quarter and sixnine months ended JuneSeptember 30, 2010, our Segment EBIT was favorably impacted by equity earnings primarily from legacy power investments and the refund of certain insurance premiums on legacy activities.

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Interest and Debt Expense
     Our interest and debt expense decreased during the quarter and sixnine months ended JuneSeptember 30, 2011 as compared to the same periods in 2010 primarily associated with the exchange or repurchase of approximately $1.4$2.1 billion of debt in 2010 and through September 30, 2011 with rates from 76.875 percent to 12 percent. Interest savings associated with our liability management transactions have been partially offset by interest costs on new borrowings. During 2011, we also had higher capitalized AFUDC related to debt on our Ruby pipeline project.
Income Taxes
                                
 Quarters Ended Six Months Ended  Quarters Ended Nine Months Ended 
 June 30, June 30,  September 30, September 30, 
 2011 2010 2011 2010  2011 2010 2011 2010 
 (In millions, except for rates)  (In millions, except for rates) 
Income taxes $38 $82 $57 $268  $(130) $75 $(73) $343 
Effective tax rate  10%  31%  11%  31%  31%  29%  (67)%  30%
     For the quarter ended September 30, 2011, our effective tax rate was impacted by the effect of a Brazilian ceiling test charge without a corresponding U.S. or Brazilian tax benefit and income attributable to nontaxable noncontrolling interests. Our negative effective tax rate for the quarter and sixnine months ended JuneSeptember 30, 2011, was favorably impacted byreflects the tax impacts of the items above, the favorable resolution of certain tax matters.matters in the first half of 2011 and a low level of pretax income resulting from our losses on the deconsolidation of Ruby and our Brazilian ceiling test charge. Absent this item,these items, the effective tax rate for the quarter and sixnine months ended JuneSeptember 30, 2011 would have been 1429 percent and 16 percent.21 percent, respectively. Our effective tax rate is expected to remain well below the statutory rate due to the growth of earnings attributable to noncontrolling interestsinterests. In addition, in the fourth quarter of EPB.2011 we will record a significant deferred state tax benefit of approximately $65 million due to an expected reduction to state tax rates as a result of a conversion of one of our subsidiaries to a limited liability company.
     For a further discussion of our effective tax rates and other matters impacting our income taxes, see Item 1, Financial Statements, Note 4.5.
Commitments and Contingencies
     For a further discussion of our commitments and contingencies, see Item 1, Financial Statements, Note 8,10, which is incorporated herein by reference and our 2010 Annual Report on Form 10-K.

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Liquidity and Capital Resources
     Available Liquidity and Liquidity Outlook for 2011. As of JuneSeptember 30, 2011 we had approximately $2.7$1.5 billion of available liquidity (exclusive of cash and credit facility capacity of EPB and Ruby)EPB). The increase in our available liquidity duringDuring the first sixnine months of 2011, waswe (i) generated operating cash flow of approximately $1.6 billion, (ii) spent approximately $3.0 billion primarily in our capital programs, (iii) refinanced approximately $2.25 billion of our revolving credit facilities (excluding the result of receiving$1.0 billion EPPOC revolving credit facility also refinanced in May 2011) to extend these maturities to 2016 and (iv) received approximately $1.4 billion in cash in conjunction with contributing additional ownership interests in SNG and CIG to our MLP which funded the acquisitions primarily through the issuance of common units and debt. During the first halfAs of September 30, 2011, our remaining 2011 capital expenditures are approximately $0.7 billion and our remaining 2011 debt maturities are approximately $91 million, which we refinanced approximately $2.25 billion of our revolving credit facilities (excluding the $1.0 billion EPPOC revolving credit facility also refinancedwill repay as they mature. Additionally, in May 2011). In July 2011, our unsecured $500 million unsecured credit facility matured.
     Our planned 2011 capital expenditures will allowhave allowed us to place a substantial portion of our pipeline backlog in service by the end ofin 2011 while continuing to support our exploration and production strategy.program. Our cash capital expenditures for the sixnine months ended JuneSeptember 30, 2011, and the amount of cash we expect to spend for the remainder of 2011 to grow and maintain our businesses are as follows:
                        
 Six Months Ended 2011    Nine Months Ended 2011 
 June 30, 2011 Remaining Total  September 30, 2011 Remaining Total 
 (In billions)             (In billions)
Pipelines
  
Maintenance $0.2 $0.1 $0.3  $0.3 $— $0.3 
Growth(1)
 1.1 0.4 1.5  1.5 0.1 1.6 
Exploration and Production
 0.6 1.0 1.6  1.1 0.5 1.6 
Other(2)
 0.1 0.1 0.2  0.1 0.1 0.2 
              
 $2.0 $1.6 $3.6  $3.0 $0.7 $3.7 
              
 
(1) Our pipeline growth capital expenditures reflect 100 percent of the capital related to the Ruby pipeline project. In September 2011, we deconsolidated Ruby and began reflecting our investment in Ruby as an investment in an unconsolidated affiliate on our balance sheet.
 
(2) Includes $100$90 million related to our midstream business.
     In July 2011, the Ruby pipeline project was placed in service. GIP, our 50 percent partner, has provided $700 million to support the project. Our obligation to repay these amounts, if required, is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in our MLP. UponIn September 2011, upon making certain permitting representations and obtaining consents and/or waiversmeeting certain other conditions, El Paso’s guarantee of certain customary conditions (that we anticipate within 60 to 90 days after Ruby’sGIP’s $700 million investment in service date of July 28, 2011),Ruby and Cheyenne Plains (an entity that owns our Cheyenne Plains pipeline) expired and the Ruby project financing obligations will becomebecame non-recourse to us and GIP will no longer be able to require us to repay its investment. As of July 31, 2011, we also had $100 million outstanding ($170 million as of June 30, 2011) in letters of credit related to Ruby.us. For a further description of this project and our agreement with GIP, see Item 1, Financial Statements, Note 15 and our 2010 Annual Report on Form 10-K and Note 12..
     We expect our current liquidity sources and operating cash flow will be sufficient to fund our estimated 2011 capital program. As of June 30, 2011, we also haveprogram and remaining 2011 debt maturities of approximately $0.4 billion ($0.6 billion through June 30, 2012) which we will repay as they mature.maturities. As a result of our current available liquidity, the hedging program we have in place on our oil and natural gas production, completed and targeted non-core exploration and production asset sales, and planned future actions (including continuing with our MLP drop down strategy as markets permit), we believe we are well positioned to meet our obligations as well as continue with our efforts to strengthen our balance sheet.obligations. We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements as well as address further changes in the financial and commodity markets.
     There are a number of factors that could impact our future plans, including completion of our announced merger with KMI, our ability to access the financial markets to if these markets are restricted, or a further decline in commodity prices. If these events occur, or fail to occur, additional adjustments to our plan and outlook may be required, including reductions in our discretionary capital program or reductions in operating and general and administrative expenses, obtaining secured financing arrangements, seeking additional partners for other growth projects and the sale of additional non-core assets, all of which could impact our financial and operating performance.

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     Overview of Cash Flow Activities.During the first sixnine months of 2011, we generated operating cash flow of approximately $1.0$1.6 billion primarily from our pipeline and exploration and production operations. We also generated approximately $3.0$5.2 billion through the refinancing and issuance of debt, including borrowings under revolving credit facilities, and an additional $0.9 billion from the issuance of MLP common units. We used cash flow generated from these operating and financing activities primarily to fund $2.0$3.0 billion in capital expenditures under our capital programs and to make $2.9$5.0 billion in repayments under our various credit facilities and other debt obligations. For the sixnine months ended JuneSeptember 30, 2011, our cash flows are summarized as follows:
        
 2011  2011 
 (In billions)  (In billions) 
Cash Flow from Operations
  
Operating activities
  
Net income $0.5  $0.2 
Ceiling test charges 0.2 
Loss on deconsolidation of subsidiary 0.6 
Other income adjustments 0.5  0.8 
Change in assets and liabilities  (0.2)
      
Total cash flow from operations $1.0  $1.6 
      
Other Cash Inflows
 
Investing activities
 
Net proceeds from the sale of assets and investments 0.6 
    
Other Cash Inflows
 
Financing activities
  
Net proceeds from the issuance of long-term debt 3.0  5.2 
Net proceeds from the issuance of noncontrolling interests 0.9  0.9 
Other 0.1 
   
 $6.2 
      
Total other cash inflows $3.9  $6.8 
   
    
Cash Outflows
  
Investing activities
  
Capital expenditures 2.0  3.0 
Other 0.1  0.2 
      
 $2.1  $3.2 
      
 
Financing activities
  
Payments to retire long-term debt and other financing obligations 2.9  5.0 
Distributions to holders of preferred stock of subsidiary and other 0.2 
   
    $5.2 
    
Total cash outflows $5.0  $8.4 
      
Net change in cash $(0.1) $— 
      

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
     This information updates, and should be read in conjunction with the information disclosed in our 2010 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
     There have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2010 Annual Report on Form 10-K, except as presented below:
Commodity Price Risk
     The table below presents the hypothetical sensitivity of our production-related derivatives and our other commodity-based derivatives to changes in fair values arising from immediate selected potential changes in the market prices (primarily natural gas, oil and power prices and basis differentials) used to value these contracts. This table reflects the sensitivities of the derivative contracts only and does not reflect any impacts on the underlying hedged commodities.
                                        
 Change in Market Price  Change in Market Price 
 10 Percent Increase 10 Percent Decrease  10 Percent Increase 10 Percent Decrease 
 Fair Value Fair Value Change Fair Value Change  Fair Value Fair Value Change Fair Value Change 
 (In millions)  (In millions) 
Production-related derivatives—net assets (liabilities)
  
June 30, 2011 $126 $(76) $(202) $315 $189 
September 30, 2011 $296 $165 $(131) $423 $127 
December 31, 2010 $237 $33 $(204) $434 $197  $237 $33 $(204) $434 $197 
 
Other commodity-based derivatives—net assets (liabilities)
  
June 30, 2011 $(372) $(371) $1 $(374) $(2)
September 30, 2011 $(341) $(339) $2 $(343) $(2)
December 31, 2010 $(423) $(422) $1 $(426) $(3) $(423) $(422) $1 $(426) $(3)

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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
     As of JuneSeptember 30, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of JuneSeptember 30, 2011.
Changes in Internal Control over Financial Reporting
     There were no changes in our internal control over financial reporting during the secondthird quarter of 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II—OTHER INFORMATION
Item 1. Legal Proceedings
     See Part I, Item 1, Financial Statements, Note 8,10, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our 2010 Annual Report on Form 10-K filed with the SEC.
Item 1A. Risk Factors
CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
     We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:
 • earnings per share;
 
 • capital and other expenditures;
 
 • dividends;
 
 • financing plans;
 
 • capital structure;
 
 • liquidity and cash flow;
 
 • pending legal proceedings, claims and governmental proceedings, including environmental matters;
 
 • future economic and operating performance;
 
 • operating income;
 
 • management’s plans; and
 
 • goals and objectives for future operations.operations;
•the satisfaction of closing conditions to the merger agreement with KMI and the completion of the proposed transactions, as well as KMI’s ability to obtain adequate financing to fund the merger consideration.
     Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2010 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. Below are additional risk factors as a result of the recent announcement to separate into two publicly traded businesses.of KMI’s proposed transactions with El Paso.

4548

Risks Related to the Proposed Separation PlanTransactions
Kinder Morgan and El Paso may be unable to obtain the regulatory clearances and approvals required to complete the transactions or, in order to do so, Kinder Morgan and El Paso may be required to comply with material restrictions or conditions.
     The proposed transactions with Kinder Morgan that were announced on October 16, 2011 are subject to review by the Federal Trade Commission under the Hart-Scott-Rodino Act, as well as several other agencies. The closing of the transactions is also subject to the condition that there be no law, injunction, judgment or ruling by a governmental authority in effect seeking to enjoin, restrain, prevent or prohibit the transactions contemplated by the merger agreement. We can provide no assurance that all required regulatory approvals will be obtained. For example, governmental authorities could seek to block or challenge the transactions as they deem necessary or desirable in the public interest at any time, including after completion of the transactions. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under such jurisdiction’s antitrust laws challenging or seeking to enjoin the transactions, before or after it is completed. Kinder Morgan may not prevail and may incur significant costs in defending or settling any action under the antitrust laws. Further, even if such approvals are obtained, the governmental agencies may seek to impose certain restrictions or obligations on Kinder Morgan’s or El Paso’s businesses as conditions for such approval, which could include requiring the divestiture of certain assets or businesses including potential divestitures of certain assets or businesses of Kinder Morgan Energy Partners, L.P. (KMP) or EPB that would require the consent of KMP or EPB, as the case may be. These actions could have the effect of delaying or preventing completion of the proposed transactions or imposing additional costs on or limiting the revenues of El Paso and the combined company following the transactions.
If our plan to separate our exploration and production businessKinder Morgan’s financing for the transactions is delayed or not completed, our stock price may decline and our growth potentialfunded, the transactions may not be enhanced.completed and Kinder Morgan may be in breach of the merger agreement.
     Kinder Morgan intends to finance the cash required in connection with the transactions, including for expenses incurred in connection with the transactions, with debt financing. On May 24,October 16, 2011, we announced that our Board of Directors had granted initial approvalKinder Morgan entered into a financing commitment letter with Barclays Capital. The commitment is subject to various conditions, including the absence of a planmaterial adverse effect on El Paso having occurred, Kinder Morgan using its commercially reasonable efforts to separateobtain credit ratings from S&P and Moody’s, the Company into two publicly traded businessesexecution of satisfactory documentation and other customary closing conditions.
     In the event the financing contemplated by the end of 2011. The plan calls for a tax-free spin-off of our explorationcommitment letter is not available, Kinder Morgan is obligated to use its best efforts to obtain alternative financing in an amount that will enable Kinder Morgan to consummate the transactions, even if such alternative financing is on less favorable terms and production businessconditions than those contemplated by the commitment letter. Under certain circumstances, Kinder Morgan may, and related activities into a new publicly traded company separate from El Paso Corporation. The completion and timingmay require Kinder Morgan to, sue its financing sources to specifically enforce the obligations of the proposed transactionfinancing sources under the commitment letter. Due to the fact that there is dependent on a number of factors includingno funding condition in the macroeconomic environment, credit markets, equity markets,merger agreement, if Kinder Morgan is unable to obtain funding from its financing sources for the receipt of a tax opinion from counsel,cash required in connection with the receipt of an Internal Revenue Service tax ruling, finalizationtransactions, Kinder Morgan could be in breach of the capital structuremerger agreement assuming all other conditions to closing are not satisfied and may be liable to El Paso for damages.
We may have difficulty attracting, motivating and retaining executives and other employees in light of the newtransactions.
     Uncertainty about the effect of the transactions on our employees may have an adverse effect on us and the combined company. This uncertainty may impair our ability to attract, retain and motivate personnel until the transactions are completed. Employee retention may be particularly challenging during the pendency of the transactions, as employees may feel uncertain about their future roles with the combined company. If our employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the transactions could be reduced.

49

Pending the completion of the required Securitiestransactions, our business and Exchange Commission filings, separation agreements betweenoperations could be materially adversely affected.
     Under the terms of the merger agreement, we are subject to certain restrictions on the conduct of our business prior to completing the transactions which may adversely affect our ability to execute certain of our business strategies, including our ability in certain cases to enter into contracts or incur capital expenditures to grow our business. The merger agreement also restricts our ability to solicit, initiate or encourage alternative acquisition proposals with any third party and may deter a potential acquirer from proposing an alternative transaction or may limit our ability to pursue any such proposal. Such limitations could negatively affect our businesses and operations prior to the completion of the transactions. Furthermore, the process of planning to integrate two companies, final approval from our Board of Directorsbusinesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on us. In connection with the pending transactions, it is possible that some customers, suppliers and other customary approvals. Wepersons with whom we have a business relationship may not complete the transaction by the end of 2011delay or on the terms that we originally announceddefer certain business decisions or we may not complete the transaction at all. If the transaction is not completedmight decide to seek to terminate, change or if it is delayed, our stock price may decline and our growth potential may not be enhanced.
If our plan to separate our exploration and production business is completed, it may not achieve the intended results.
     If the separation of our exploration and production business is completed, we may not realize the benefits that were expected due to various factors, including the failure of the businesses to operate successfully as independent entities, the reduction in scope and scalerenegotiate their relationship with us as a result of the separationtransactions, which could negatively affect our revenues, earnings and cash flows, as well as the market price of shares of our common stock, regardless of whether the businesses,transactions are completed.
We will incur substantial transaction and merger-related costs in connection with the failuretransactions.
     We expect to incur a number of non-recurring transaction and merger-related costs associated with completing the transactions, combining the operations of the two companies to grow their businesses as expected,and achieving desired synergies. These fees and costs will be substantial. Additional unanticipated costs may be incurred in the incurrence of new debt obligations in our exploration and production business, the incurrence of additional costsintegration of the companiesbusinesses of the two companies. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to operate separately, the failure to adequately develop systemsintegration of the two businesses, will offset the incremental transaction and controlsmerger-related costs over time. Thus, any net benefit may not be achieved in the explorationnear term, or at all.
Failure to complete the transactions could negatively affect the trading price El Paso common stock and productionthe future business and financial results of El Paso.
     Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by the respective stockholders of Kinder Morgan and El Paso or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the transactions are not completed, it could negatively affect the trading price of our common stock and the future business and financial results of El Paso, and we will be subject to several risks, including the following:
•the parties may be liable for damages to one another under the terms of the merger agreement;
•negative reactions from the financial markets, including declines in the price of our common stock due to the fact that current prices may reflect a market assumption that the transactions will be completed;
•having to pay certain significant costs relating to the merger, including, in the case of El Paso in certain circumstances, a termination fee of $650 million and up to $20 million in expenses related to the transaction, plus certain financing-related expenses of Kinder Morgan; and
•the attention of our management will have been diverted to the transactions rather than to our operations and pursuit of other opportunities that could have been beneficial to us, including the prior strategy to spin-off our exploration and production business.
Purported stockholder class action complaints have been filed against El Paso, Kinder Morgan, the members of El Paso’s board of directors, El Paso’s and Kinder Morgan’s merger subsidiaries and Goldman Sachs, challenging the transactions, and an unfavorable judgment or ruling in these lawsuits could prevent or delay the consummation of the proposed transactions and result in substantial costs.
     In connection with the proposed transactions, purported stockholders of El Paso have filed several stockholder class action lawsuits in the District Courts of Harris County, Texas and in the Delaware Courts of Chancery. Those lawsuits name as defendants El Paso, Kinder Morgan, the members of the board of directors of El Paso, and, in certain cases, the affiliates of El Paso and Kinder Morgan and Goldman Sachs. Among other remedies, the plaintiffs seek to enjoin the proposed transactions. If a standalone entity followingfinal settlement is not reached, or if a dismissal is not obtained, these lawsuits could prevent or delay completion of the spin-off, potential future disputestransactions and liabilities betweenresult in substantial costs to El Paso and Kinder Morgan, including any costs associated with the companies asindemnification of directors. Additional lawsuits may be filed against El Paso and Kinder Morgan, their respective affiliates and El Paso’s directors related to the proposed transactions. The defense or settlement of any lawsuit or claim may adversely affect the combined company’s business, financial condition or results of operations.

50

The proposed transactions may be completed on different terms from those contained in the merger agreement.
     Prior to completion of the transactions, the parties may amend or alter the terms of the merger agreement, including with respect to, among other things, the covenants of the parties regarding their business operations during the pendency of the proposed transactions or of Kinder Morgan regarding the debt financing (certain changes to the merger agreement, however, can only be made prior to the requisite stockholder approval). Any such amendments or alterations may have negative consequences to our stockholders and to our business, financial condition and results of operations.
Closing of the proposed transactions may trigger change in control provisions in certain agreements to which we are a party.
     Closing of the proposed transactions may trigger change in control provisions in certain agreements to which we are parties. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waiver or seek to renegotiate the agreements on less favorable terms. As a result of the separation and risks associated with our ability to retain key employeesannouncement of the separated companies. Any such difficulties couldtransactions, we were placed on negative outlook by Moody’s and Fitch. During the pendency of the proposed transactions, a decrease in Kinder Morgan’s perceived creditworthiness may have an adverse effect on our business, resultsperceived creditworthiness, possibly resulting in a downgrade of operations and financial condition.
The spin-off could result in substantial tax liability.
     We have requested a private letter ruling from the Internal Revenue Service (“IRS”) substantially to the effect that, for U.S. federal income tax purposes, the spin-off and certain related transactions will qualifycredit ratings, tightening of credit under Sections 355 and/our existing credit facilities, increasing our borrowing costs or, 368upon completion of the U.S. Internal Revenue Codetransactions with KMI, could trigger certain change of 1986, as amended (the “Code”). If the factual assumptions or representations made in the request for the private letter ruling provecontrol provisions to have been inaccurate or incomplete in any material respect, thencertain agreements to which we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whetherare a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. The private letter ruling will be based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also intend to obtain an opinion of outside counsel, substantially to the effect that, for U.S. federal income tax purposes, the spin-off and certain related transactions will qualify under Sections 355 and 368 of the Code. The opinion will rely on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion will not be binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail. As a result, there is a risk that the spin-off could ultimately be taxable to us and each stockholder of El Paso common stock who receives shares of the exploration and production company formed in conjunction with the spin-off.party.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     None.
Item 3. Defaults Upon Senior Securities
     None.

46

Item 4. (Removed and Reserved)
Item 5. Other Information
     None.
Item 6. Exhibits
     The Exhibit Index is incorporated herein by reference.
     The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
 • should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
 
 • may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
 
 • may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
 
 • were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
     Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

4751

SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, El Paso Corporation has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
     
 EL PASO CORPORATION
 		 
Date: August 5,November 4, 2011 /s/ John R. Sult   
 John R. Sult  
 Executive Vice President and Chief Financial
Officer
(Principal Financial Officer) 		 
 
   
Date: August 5,November 4, 2011 /s/ Francis C. Olmsted III   
 Francis C. Olmsted III  
 Vice President and Controller
(Principal Accounting Officer) 		 

4852

     
EL PASO CORPORATION
EXHIBIT INDEX
     Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
   
Exhibit  
Number Description
10.12.1 Fourth AmendedAgreement and Restated Credit Agreement,Plan of Merger, dated as of May 27,October 16, 2011, by and among El Paso Corporation, El Paso Natural Gas CompanySirius Holdings Merger Corporation, Sirius Merger Corporation, Kinder Morgan, Inc., Sherpa Merger Sub, Inc and Tennessee Gas Pipeline Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent for the LendersSherpa Acquisition, LLC (incorporated by reference to Exhibit 10.12.1 to our Current Report on Form 8-K filed with the SEC on June 3,October 18, 2011).
 
10.22.2 Fourth AmendedAgreement and Restated Security Agreement,Plan of Merger, dated as of May 27,October 16, 2011, by and among El Paso Corporation, the persons referred to therein as Pipeline Company Borrowers, the persons referred to therein as Subsidiary Grantors,Sirius Holdings Merger Corporation and JPMorgan Chase Bank, N.A., as Collateral Agent and Depository BankSirius Merger Corporation (incorporated by reference to Exhibit 10.22.1 to our Current Report on Form 8-K filed with the SEC on June 3,October 18, 2011).
 
10.310.1 Third Amended and Restated CreditVoting Agreement, dated as of June 2,October 16, 2011, by and among El Paso ExplorationCorporation, Richard D. Kinder, GS Capital Partners V Fund, L.P., GSCP V Offshore Knight Holdings, L.P., GSCP V Germany Knight Holdings, L.P., GS Capital Partners V Institutional, L.P., GS Capital Partners VI Fund, L.P., GSCP VI Offshore Knight Holdings, L.P., GSCP VI Germany Knight Holdings, L.P., GS Capital Partners VI Parallel, L.P., Goldman Sachs KMI Investors, L.P., GSCP KMI Investors, L.P., GSCP KMI Investors Offshore, L.P., GS Infrastructure Knight Holdings, L.P., GS Infrastructure Partners, I, L.P., GS Global Infrastructure Partners I, L.P., Highstar II Knight Acquisition Sub, L.P., Highstar III Knight Acquisition Sub, L.P., Highstar Knight Partners, L.P., Highstar KMI Blocker LLC, Carlyle Partners IV Knight, L.P., CP IV Coinvestment, L.P., Carlyle Energy Coinvestment III, L.P., Carlyle/Riverstone Knight Investment Partnership, L.P., C/R Knight Partners, L.P., C/R Energy III Knight Non-U.S. Partnership, L.P., and Production Company and El Paso E&P Company,Riverstone Energy Coinvestment III, L.P., as Borrowers and BNP Paribas, as Administrative Agent Corporation (incorporated by reference to Exhibit 10.12.1 to our Current Report on Form 8-K filed with the SEC on June 8,October 18, 2011).
 
*12 Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
 
*31.A Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
*31.B Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
*32.A Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*32.B Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*101.INS XBRL Instance Document.
 
*101.SCH XBRL Schema Document.
 
*101.CAL XBRL Calculation Linkbase Document.
 
*101.DEF XBRL Definition Linkbase Document.
 
*101.LAB XBRL Labels Linkbase Document.
 
*101.PRE XBRL Presentation Linkbase Document.

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