e10vq
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
March 31, 2007
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to .
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Commission File Number 1-14365
El Paso
Corporation
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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76-0568816
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(I.R.S. Employer
Identification No.)
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El Paso Building
1001 Louisiana Street
Houston, Texas
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77002
(Zip Code)
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(Address of Principal Executive
Offices)
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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. Yes þ No
o.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ.
Indicate the number of shares outstanding of each of the
registrants classes of common stock, as of the latest
practicable date.
Common Stock, par value $3 per share. Shares outstanding on
May 4, 2007: 700,240,771
EL PASO
CORPORATION
TABLE OF CONTENTS
Below is a list of terms that are common to our industry and
used throughout this document:
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/d
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= per day
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Mcfe
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= thousand cubic feet of natural
gas equivalents
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Bbl
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= barrels
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MMBtu
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= million British thermal units
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BBtu
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= billion British thermal units
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MMcf
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= million cubic feet
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LNG
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= liquefied natural gas
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MMcfe
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= million cubic feet of natural
gas equivalents
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MBbls
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= thousand barrels
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NGL
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= natural gas liquids
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Mcf
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= thousand cubic feet
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TBtu
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= trillion British thermal units
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When we refer to natural gas and oil 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.
i
PART
I FINANCIAL INFORMATION
Item 1. Financial
Statements
EL PASO
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
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Quarters Ended March 31,
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2007
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2006
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Operating revenues
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$
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1,022
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$
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1,337
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Operating expenses
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Cost of products and services
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55
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62
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Operation and maintenance
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301
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285
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Depreciation, depletion and
amortization
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271
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250
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Taxes, other than income taxes
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60
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57
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687
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654
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Operating income
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335
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683
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Earnings from unconsolidated
affiliates
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37
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29
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Loss on debt extinguishment
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(201
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)
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(6
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)
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Other income, net
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45
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50
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Interest and debt expense
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(283
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)
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(331
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)
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Income (loss) before income taxes
from continuing operations
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(67
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)
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425
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Income taxes
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(19
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)
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124
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Income (loss) from continuing
operations
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(48
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)
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301
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Discontinued operations, net of
income taxes
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677
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55
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Net income
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629
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356
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Preferred stock dividends
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9
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10
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Net income available to common
stockholders
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$
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620
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$
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346
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Basic earnings (loss) per common
share
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Income (loss) from continuing
operations
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$
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(0.08
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)
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$
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0.44
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Discontinued operations, net of
income taxes
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0.97
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0.09
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Net income per common share
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$
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0.89
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$
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0.53
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Diluted earnings (loss) per common
share
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Income (loss) from continuing
operations
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$
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(0.08
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)
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$
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0.42
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Discontinued operations, net of
income taxes
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0.97
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0.07
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Net income per common share
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$
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0.89
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$
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0.49
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Dividends declared per common share
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$
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0.04
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$
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0.04
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See accompanying notes.
1
EL PASO
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
(Unaudited)
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March 31,
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December 31,
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2007
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2006
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ASSETS
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Current assets
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Cash and cash equivalents
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$
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232
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$
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537
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Accounts and notes receivable
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Customer, net of allowance of $21
in 2007 and $28 in 2006
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475
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516
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Affiliates
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197
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192
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Other
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482
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495
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Assets from price risk management
activities
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96
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436
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Assets held for sale and from
discontinued operations
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4,161
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Deferred income taxes
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345
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478
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Other
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414
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352
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Total current assets
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2,241
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7,167
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Property, plant and equipment, at
cost
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Pipelines
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15,789
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15,672
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Natural gas and oil properties, at
full cost
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17,098
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16,572
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Other
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562
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566
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33,449
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32,810
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Less accumulated depreciation,
depletion and amortization
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16,243
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16,132
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Total property, plant and
equipment, net
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17,206
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16,678
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Other assets
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Investments in unconsolidated
affiliates
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1,671
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1,707
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Assets from price risk management
activities
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214
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414
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Other
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1,331
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1,295
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3,216
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3,416
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Total assets
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$
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22,663
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$
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27,261
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See accompanying notes.
2
EL PASO
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
(Unaudited)
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March 31,
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December 31,
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2007
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2006
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LIABILITIES AND STOCKHOLDERS
EQUITY
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Current liabilities
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Accounts payable
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Trade
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$
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367
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$
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478
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Affiliates
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2
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3
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Other
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552
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569
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Current maturities of long-term
financing obligations
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403
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1,360
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Liabilities from price risk
management activities
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338
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278
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Liabilities related to
discontinued operations
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1,817
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Accrued interest
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233
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269
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Other
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1,074
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1,377
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Total current liabilities
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2,969
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|
|
|
6,151
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Long-term financing obligations,
less current maturities
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11,263
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13,329
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Other
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Liabilities from price risk
management activities
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947
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924
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Deferred income taxes
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1,047
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950
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Other
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1,718
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1,690
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3,712
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3,564
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Commitments and contingencies
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Securities of subsidiaries
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22
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31
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Stockholders equity
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Preferred stock, par value
$0.01 per share; authorized 50,000,000 shares; issued
750,000 shares of 4.99% convertible perpetual stock;
stated at liquidation value
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750
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750
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Common stock, par value
$3 per share; authorized 1,500,000,000 shares; issued
706,100,142 shares in 2007 and 705,833,206 shares in
2006
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2,118
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|
|
|
2,118
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Additional paid-in capital
|
|
|
4,769
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|
|
|
4,804
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|
Accumulated deficit
|
|
|
(2,315
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)
|
|
|
(2,940
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)
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Accumulated other comprehensive
loss
|
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|
(446
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)
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|
(343
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)
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Treasury stock (at cost);
7,771,602 shares in 2007 and 8,715,288 shares in 2006
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(179
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)
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|
(203
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)
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|
|
|
|
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Total stockholders equity
|
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|
4,697
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|
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4,186
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Total liabilities and
stockholders equity
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$
|
22,663
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$
|
27,261
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|
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|
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See accompanying notes.
3
EL PASO
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
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|
|
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Quarters Ended March 31,
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|
|
2007
|
|
|
2006
|
|
|
Cash flows from operating
activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
629
|
|
|
$
|
356
|
|
Less income from discontinued
operations, net of income taxes
|
|
|
677
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before
discontinued operations
|
|
|
(48
|
)
|
|
|
301
|
|
Adjustments to reconcile net
income to net cash from operating activities
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
271
|
|
|
|
250
|
|
Deferred income tax expense
(benefit)
|
|
|
(18
|
)
|
|
|
121
|
|
Earnings from unconsolidated
affiliates, adjusted for cash distributions
|
|
|
37
|
|
|
|
9
|
|
Loss on debt extinguishment
|
|
|
201
|
|
|
|
6
|
|
Other
|
|
|
(2
|
)
|
|
|
15
|
|
Asset and liability changes
|
|
|
(93
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)
|
|
|
160
|
|
|
|
|
|
|
|
|
|
|
Cash provided by continuing
activities
|
|
|
348
|
|
|
|
862
|
|
Cash provided by (used in)
discontinued activities
|
|
|
(35
|
)
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
313
|
|
|
|
951
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(783
|
)
|
|
|
(373
|
)
|
Net proceeds from the sale of
assets and investments
|
|
|
38
|
|
|
|
59
|
|
Other
|
|
|
2
|
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
Cash used in continuing activities
|
|
|
(743
|
)
|
|
|
(292
|
)
|
Cash provided by (used in)
discontinued activities
|
|
|
3,678
|
|
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
investing activities
|
|
|
2,935
|
|
|
|
(320
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of
long-term debt
|
|
|
1,424
|
|
|
|
|
|
Payments to retire long-term debt
and other financing obligations
|
|
|
(4,654
|
)
|
|
|
(946
|
)
|
Dividends paid
|
|
|
(37
|
)
|
|
|
(36
|
)
|
Contributions from discontinued
operations
|
|
|
3,360
|
|
|
|
59
|
|
Other
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in)
continuing activities
|
|
|
90
|
|
|
|
(923
|
)
|
Cash used in discontinued
activities
|
|
|
(3,643
|
)
|
|
|
(61
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in financing
activities
|
|
|
(3,553
|
)
|
|
|
(984
|
)
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
(305
|
)
|
|
|
(353
|
)
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
537
|
|
|
|
2,132
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
232
|
|
|
$
|
1,779
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
4
EL PASO
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Net income
|
|
$
|
629
|
|
|
$
|
356
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation
adjustments (net of income tax of less than $1 in 2006)
|
|
|
|
|
|
|
3
|
|
Net reclassification adjustments
associated with pension and other postretirement obligations
(net of income tax of $3 in 2007)
|
|
|
6
|
|
|
|
|
|
Net gains (losses) from cash flow
hedging activities:
|
|
|
|
|
|
|
|
|
Unrealized
mark-to-market
gains (losses) arising during period (net of income tax of $47
in 2007 and $76 in 2006)
|
|
|
(83
|
)
|
|
|
131
|
|
Reclassification adjustments for
changes in initial value to settlement date (net of income tax
of $15 in 2007 and $11 in 2006)
|
|
|
(25
|
)
|
|
|
20
|
|
Net unrealized gains arising
during period associated with investments available for sale
(net of income tax of $2 in 2007 and $8 in 2006)
|
|
|
3
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
|
(99
|
)
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
530
|
|
|
$
|
525
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
5
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). Because this is 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. You should read this Quarterly Report on
Form 10-Q
along with our 2006 Annual Report on
Form 10-K,
which contains a summary of our significant accounting policies
and other disclosures. The financial statements as of
March 31, 2007, and for the quarters ended March 31,
2007 and 2006, are unaudited. We derived the condensed
consolidated balance sheet as of December 31, 2006, from
the audited balance sheet filed in our 2006 Annual Report on
Form 10-K.
In our opinion, we have made all adjustments which are of a
normal, recurring nature to fairly present our interim period
results. Due to the seasonal nature of our businesses,
information for interim periods may not be indicative of our
results of operations for the entire year. Our results for all
periods reflect ANR Pipeline Company (ANR), our Michigan storage
assets and our 50 percent interest in Great Lakes Gas
Transmission (Great Lakes), as well as our Macae power facility
in Brazil as discontinued operations. Additionally, our
financial statements for prior periods include reclassifications
that were made to conform to the current period presentation.
Those reclassifications did not impact our reported net income
or stockholders equity.
Significant
Accounting Policies
The information below provides updating information with respect
to our significant accounting policies and accounting
pronouncements issued but not yet adopted discussed in our 2006
Annual Report on
Form 10-K.
Accounting for Uncertainty in Income Taxes. On
January 1, 2007, we adopted Financial Accounting Standards
Board (FASB) Interpretation (FIN) No. 48, Accounting for
Uncertainty in Income Taxes and its related interpretation.
FIN No. 48 clarifies Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes,
and requires us to evaluate our tax positions for all
jurisdictions and for all years where the statute of limitations
has not expired. FIN No. 48 requires companies to meet
a more-likely-than-not threshold (i.e. greater than
a 50 percent likelihood of a tax position being sustained
under examination) prior to recording a benefit for their tax
positions. Additionally, for tax positions meeting this
more-likely-than-not threshold, the amount of
benefit is limited to the largest benefit that has a greater
than 50 percent probability of being realized upon ultimate
settlement. For further information on the impact on our
financial statements of the adoption of this interpretation, see
Note 3.
Accounting for Offsetting Contractual
Amounts. In April 2007, the FASB issued FASB
Staff Position (FSP) No.
FIN 39-1.
The FSP amends FASB Interpretation No. 39, Offsetting of
Amounts Related to Certain Contracts, and allows companies
to offset amounts recorded for the fair value of derivative
contracts with the related amounts of cash collateral posted or
held if the contracts are executed with the same counterparty
under the same master netting arrangement. This pronouncement is
effective for fiscal years beginning after November 15,
2007, although early application is permitted. We are currently
evaluating the impact of this pronouncement on our assets and
liabilities from price risk management contracts and amounts
recorded for broker margin and deposits.
Under SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, we classify assets to be
disposed of as held for sale or, if appropriate, discontinued
operations when they have received appropriate approvals to be
disposed of by our management or Board of Directors and when
they meet other criteria. Cash flows from our discontinued
businesses are reflected as discontinued operating, investing,
and financing activities in our statement of cash flows. To the
extent these operations do not maintain separate cash balances,
we reflect the net cash flows generated from these businesses as
a contribution to our continuing operations in cash from
continuing
6
financing activities. As of December 31, 2006, we had total
assets of $4.1 billion and total liabilities of
$1.8 billion related to our discontinued operations, the
composition of which is disclosed in our 2006 Annual Report on
Form 10-K.
We also had $28 million of assets held for sale as of
December 31, 2006. As of March 31, 2007, all of our
assets and liabilities related to our discontinued operations
and our assets held for sale had been sold. The following is a
description of each of our discontinued operations:
ANR and Related Operations. During the first
quarter of 2007, we sold ANR, our Michigan storage assets and
our 50 percent interest in Great Lakes to TransCanada
Corporation and TC Pipeline, LP for net cash proceeds of
approximately $3.7 billion and recorded a gain of
approximately $651 million, net of taxes of
$356 million on the sale. Included in the net assets of
these discontinued operations as of the date of the sale were
net deferred tax liabilities assumed by TransCanada.
International Power Operations. During 2006,
we completed the sale of all of our discontinued international
power operations for net proceeds of approximately
$368 million including our interest in Macae, a wholly
owned power plant facility in Brazil, and certain power assets
in Asia and Central America.
Below is summarized income statement information regarding our
discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ANR and
|
|
|
International
|
|
|
|
|
|
|
Related
|
|
|
Power
|
|
|
|
|
|
|
Operations
|
|
|
Operations
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Quarter Ended March 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
101
|
|
|
$
|
|
|
|
$
|
101
|
|
Costs and expenses
|
|
|
(43
|
)
|
|
|
|
|
|
|
(43
|
)
|
Other
expense(1)
|
|
|
(7
|
)
|
|
|
|
|
|
|
(7
|
)
|
Interest and debt expense
|
|
|
(10
|
)
|
|
|
|
|
|
|
(10
|
)
|
Income taxes
|
|
|
(15
|
)
|
|
|
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
Gain on sale, net of income taxes
of $356 million
|
|
|
651
|
|
|
|
|
|
|
|
651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued
operations
|
|
$
|
677
|
|
|
$
|
|
|
|
$
|
677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31,
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
194
|
|
|
$
|
50
|
|
|
$
|
244
|
|
Costs and expenses
|
|
|
(77
|
)
|
|
|
(65
|
)
|
|
|
(142
|
)
|
Other income
|
|
|
15
|
|
|
|
|
|
|
|
15
|
|
Interest and debt expense
|
|
|
(17
|
)
|
|
|
(7
|
)
|
|
|
(24
|
)
|
Income taxes
|
|
|
(41
|
)
|
|
|
3
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from
discontinued operations
|
|
$
|
74
|
|
|
$
|
(19
|
)
|
|
$
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes a loss of approximately
$19 million associated with the extinguishment of certain
debt obligations.
|
Income taxes included in our income (loss) from continuing
operations for the quarters ended March 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except rates)
|
|
|
Income taxes
|
|
$
|
(19
|
)
|
|
$
|
124
|
|
Effective tax rate
|
|
|
28
|
%
|
|
|
29
|
%
|
We compute our quarterly 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. Significant tax items, which may
7
include the conclusion of income tax audits, are recorded in the
period that the specific item occurs. During both the first
quarter of 2007 and 2006, our overall effective tax rate on
continuing operations was different than the statutory rate of
35 percent primarily due to state income taxes (net of
federal income tax effects) and earnings/losses from
unconsolidated affiliates where we anticipate receiving
dividends. Additionally, during the first quarter of 2006, our
overall effective tax rate on continuing operations was
different than the statutory rate of 35 percent due to the
conclusion of IRS audits resulting in the reduction of tax
contingencies of $16 million.
We file income tax returns in the U.S. federal
jurisdiction, and various state and foreign jurisdictions. With
a few exceptions, we are no longer subject to U.S. federal,
state and local, or
non-U.S. income
tax examinations by tax authorities for years before 1999.
Certain issues raised on examination by tax authorities on
El Pasos 2003 and 2004 federal tax years are
currently being appealed. For our open tax years, we have
unrecognized tax benefits (liabilities for uncertain tax
matters) which could increase or decrease our income tax expense
and effective income tax rates as these matters are finalized.
Upon the adoption of FIN No. 48, we recorded
additional liabilities for unrecognized tax benefits of
$2 million, including interest and penalties, which we
accounted for as an increase of $4 million to the
January 1, 2007 accumulated deficit and an increase of
$2 million to additional paid in capital. The additional
amounts recorded increased our overall unrecognized tax benefits
(including interest and penalties) to $178 million as of
January 1, 2007. Of this amount, approximately
$109 million (net of federal tax benefits) would favorably
affect our income tax expense and our effective income tax rate
if recognized in future periods. While the amount of our
unrecognized tax benefits could change in the next twelve
months, we do not expect this change to have a significant
impact on our results of operations or financial position.
We recognize accrued interest and penalties related to
unrecognized tax benefits in income tax expense on our income
statement. Total accrued interest and penalties recognized in
our income statement was not material for the quarters ended
March 31, 2007 and 2006. As of January 1, 2007 and
March 31, 2007, we had approximately $39 million and
$41 million of liabilities for interest and penalties
related to our unrecognized tax benefits.
8
We calculated basic and diluted earnings per common share as
follows for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Basic
|
|
|
Diluted
|
|
|
Basic
|
|
|
Diluted
|
|
|
|
(In millions, except per share amounts)
|
|
|
Income (loss) from continuing
operations
|
|
$
|
(48
|
)
|
|
$
|
(48
|
)
|
|
$
|
301
|
|
|
$
|
301
|
|
Convertible preferred stock
dividends
|
|
|
(9
|
)
|
|
|
(9
|
)
|
|
|
(10
|
)
|
|
|
|
|
Interest on trust preferred
securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations available to common stockholders
|
|
|
(57
|
)
|
|
|
(57
|
)
|
|
|
291
|
|
|
|
303
|
|
Discontinued operations, net of
income taxes
|
|
|
677
|
|
|
|
677
|
|
|
|
55
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
stockholders
|
|
$
|
620
|
|
|
$
|
620
|
|
|
$
|
346
|
|
|
$
|
358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding
|
|
|
694
|
|
|
|
694
|
|
|
|
656
|
|
|
|
656
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options and restricted stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
Convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57
|
|
Trust preferred securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding and dilutive securities
|
|
|
694
|
|
|
|
694
|
|
|
|
656
|
|
|
|
724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations
|
|
$
|
(0.08
|
)
|
|
$
|
(0.08
|
)
|
|
$
|
0.44
|
|
|
$
|
0.42
|
|
Discontinued operations, net of
income taxes
|
|
|
0.97
|
|
|
|
0.97
|
|
|
|
0.09
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
0.89
|
|
|
$
|
0.89
|
|
|
$
|
0.53
|
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We exclude potentially dilutive securities (such as employee
stock options, restricted stock, convertible preferred stock,
and trust preferred securities) from the determination of
diluted earnings per share (as well as their related income
statement impacts) when their impact on income from continuing
operations per common share is antidilutive. For the quarter
ended March 31, 2007, we incurred losses from continuing
operations and accordingly excluded all of our potentially
dilutive securities from the determination of diluted earnings
per share as their impact on loss per common share was
antidilutive. For the quarter ended March 31, 2006, certain
employee stock options and our zero coupon convertible
debentures (redeemed in April 2006) were antidilutive. For
a further discussion of our potentially dilutive securities, see
our 2006 Annual Report on
Form 10-K.
9
|
|
5.
|
Price
Risk Management Activities
|
The following table summarizes the carrying value of the
derivatives used in our price risk management activities as of
March 31, 2007 and December 31, 2006. In the table,
derivatives designated as accounting hedges consist of
instruments used to hedge our natural gas and oil production.
Other commodity-based derivative contracts relate to derivative
contracts not designated as accounting hedges, such as options
and swaps, other natural gas and power purchase and supply
contracts, and derivatives from our historical energy trading
activities. Interest rate and foreign currency derivatives
consist of swaps that are primarily designated as hedges of our
interest rate and foreign currency risk on long-term debt.
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Net assets (liabilities):
|
|
|
|
|
|
|
|
|
Derivatives designated as
accounting hedges
|
|
$
|
(86
|
)
|
|
$
|
61
|
|
Other commodity-based derivative
contracts(1)
|
|
|
(932
|
)
|
|
|
(456
|
)
|
|
|
|
|
|
|
|
|
|
Total commodity-based derivatives
|
|
|
(1,018
|
)
|
|
|
(395
|
)
|
Interest rate and foreign currency
derivatives
|
|
|
43
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
Net liabilities from price risk
management activities
|
|
$
|
(975
|
)
|
|
$
|
(352
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the first quarter of 2007,
we settled contracts associated with approximately
$381 million of our assets from price risk management
activities by applying the related cash margin we held against
amounts due under those contracts. This non-cash transaction is
not reflected in our statement of cash flows.
|
|
|
6.
|
Long-Term
Financing Obligations and Other Credit Facilities
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Current maturities of long-term
financing obligations
|
|
$
|
403
|
|
|
$
|
1,360
|
|
Long-term financing obligations
|
|
|
11,263
|
|
|
|
13,329
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11,666
|
|
|
$
|
14,689
|
|
|
|
|
|
|
|
|
|
|
10
Changes in Long-Term Financing
Obligations. During the quarter ended
March 31, 2007, we had the following changes in our
long-term financing obligations (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
Book Value
|
|
|
Received /
|
|
Company
|
|
Interest Rate
|
|
Increase (Decrease)
|
|
|
(Paid)
|
|
|
Issuances
|
|
|
|
|
|
|
|
|
|
|
El Paso Exploration and
Production Company (EPEP) revolving credit facility
|
|
variable
|
|
$
|
255
|
|
|
$
|
255
|
|
El Paso revolving credit
facility
|
|
variable
|
|
|
675
|
|
|
|
675
|
|
Southern Natural Gas (SNG) notes
|
|
5.900%
|
|
|
500
|
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
Increases through
March 31, 2007
|
|
|
|
$
|
1,430
|
|
|
$
|
1,424
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayments, repurchases, and
other
|
|
|
|
|
|
|
|
|
|
|
Notes/Other
|
|
|
|
|
|
|
|
|
|
|
El Paso
|
|
6.375%-10.75%
|
|
$
|
(2,837
|
)
|
|
$
|
(3,011
|
)
|
El Paso - Euro
|
|
7.125%
|
|
|
(157
|
)
|
|
|
(165
|
)
|
SNG
|
|
6.700%
|
|
|
(52
|
)
|
|
|
(52
|
)
|
SNG
|
|
8.875%
|
|
|
(398
|
)
|
|
|
(418
|
)
|
Other
|
|
various
|
|
|
(9
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,453
|
)
|
|
|
(3,654
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Revolving Credit
Facilities
|
|
|
|
|
|
|
|
|
|
|
EPEP
|
|
variable
|
|
|
(200
|
)
|
|
|
(200
|
)
|
El Paso
|
|
variable
|
|
|
(800
|
)
|
|
|
(800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,000
|
)
|
|
|
(1,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Decreases through
March 31, 2007
|
|
|
|
$
|
(4,453
|
)
|
|
$
|
(4,654
|
)
|
|
|
|
|
|
|
|
|
|
|
|
In the first quarter of 2007, we recorded a $201 million
pre-tax loss on the extinguishment of certain of the debt
repurchased above. In April 2007, we issued $355 million of
El Paso Natural Gas Company (EPNG) 5.95% notes due in
2017 and repaid approximately $301 million of EPNG
7.625% notes.
Approximately $100 million of our debt obligations are
redeemable at the option of the holders in the second quarter of
2007, which is prior to its stated maturity date. As a result,
these amounts are classified as current liabilities in our
balance sheet as of March 31, 2007. In addition,
approximately $7 billion of our debt obligations
(increasing to approximately $9 billion by the end of
2008) provide us the ability to call the debt prior to its
stated maturity date. If redeemed prior to their stated
maturities, we will be required to pay a make-whole or fixed
premium in addition to repaying the principal and accrued
interest.
Prior to their redemption in 2006, we recorded accretion expense
on our zero coupon debentures. During the quarter ended
March 31, 2006, we redeemed $612 million of our zero
coupon debentures, of which $110 million represented an
increase in the principal balance of long-term debt due to the
accretion of interest on the debentures we redeemed. We account
for these redemptions as financing activities in our statement
of cash flows.
Credit
Facilities
Credit Agreements. As of March 31, 2007,
we had available capacity under our credit agreements of
approximately $1.1 billion. Of this amount, approximately
$0.3 billion is related to the $500 million revolving
credit agreement of our subsidiary, EPEP, and approximately
$0.8 billion is available under our $1.75 billion
credit agreement and our $500 million unsecured revolving
credit facility. As a result of upgrades to our credit ratings,
we can now borrow funds under the $1.75 billion credit
agreement at rates of LIBOR plus 1.25% or issue letters of
credit at a rate of 1.40%. The commitment fee on any unused
capacity under the $1.25 billion revolving credit facility
of that agreement is 0.25%.
11
Contingent Letter of Credit Facility. In
January 2007, we entered into a $250 million unsecured
contingent letter of credit facility that matures in March 2008.
Letters of credit are available to us under the facility if the
average NYMEX gas price strip for the remaining calendar months
through March 2008 is equal to or exceeds $11.75 per MMBtu.
The facility fee, if triggered, is 1.66% per annum.
Letters of Credit. We enter into letters of
credit in the ordinary course of our operating activities as
well as periodically in conjunction with the sales of assets or
businesses. As of March 31, 2007, we had outstanding
letters of credit of approximately $1.5 billion of which
approximately $1.0 billion secures our recorded obligations
related to price risk management activities.
|
|
7.
|
Commitments
and Contingencies
|
Legal
Proceedings
Shareholder Litigation. Twenty-eight purported
shareholder class action lawsuits have been pending since 2002
and are consolidated in federal court in Houston, Texas. The
consolidated lawsuit alleges violations of federal securities
laws against us and several of our current and former officers
and directors. In November 2006, the parties executed a
definitive settlement agreement in which the parties agreed to
settle these class action lawsuits. Pursuant to the terms of the
settlement, El Paso contributed approximately
$48 million, its insurers have contributed approximately
$225 million and a third party contributed $12 million
into an escrow account. The settlement was approved by the court
in the first quarter of 2007 and became final in April 2007.
ERISA Class Action Suits. In December
2002, a purported class action lawsuit entitled William H.
Lewis, III v. El Paso Corporation,
et al. was filed in the U.S. District Court for
the Southern District of Texas alleging that our communication
with participants in our Retirement Savings Plan included
misrepresentations and omissions similar to those pled in the
consolidated shareholder litigation that caused members of the
class to hold and maintain investments in El Paso stock in
violation of the Employee Retirement Income Security Act
(ERISA). A briefing schedule has been set for dispositive
motions. We have insurance coverage for this lawsuit, subject to
certain deductibles and co-pay obligations. We have established
accruals for these matters which we believe are adequate.
Cash Balance Plan Lawsuit. In December 2004, a
purported class action lawsuit entitled Tomlinson,
et al. v. El Paso Corporation and El Paso
Corporation Pension Plan was filed in U.S. District
Court for Denver, Colorado. The lawsuit alleges various
violations of 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.
Certain plaintiffs claims that our cash balance plan
violated ERISA were recently dismissed by the trial court. Our
costs and legal exposure related to this lawsuit are not
currently determinable.
Retiree Medical Benefits Matters. We currently
serve as the plan administrator for a medical benefits plan that
covers a closed group of retirees of the Case Corporation who
retired on or before July 1, 1994. Case was formerly a
subsidiary of Tenneco, Inc. that was spun off prior to our
acquisition of Tenneco in 1996. Tenneco retained the obligation
to provide certain medical and prescription drug benefits to
eligible retirees and their spouses. We assumed this obligation
as a result of our merger with Tenneco. Pursuant to an agreement
with the applicable union for Case employees, our liability for
these benefits was subject to a cap, such that costs in excess
of the cap are assumed by plan participants. In 2002, we and
Case were sued by individual retirees in a federal court in
Detroit, Michigan in an action entitled Yolton
et al. v. El Paso Tennessee Pipeline Co. and Case
Corporation. The suit alleges, among other things, that
El Paso and Case violated ERISA and that they should be
required to pay all amounts above the cap. Case further filed
claims against El Paso asserting that El Paso is
obligated to indemnify, defend and hold Case harmless for the
amounts it would be required to pay. In separate rulings in
2004, the court ruled that, pending a trial on the merits, Case
must pay the amounts incurred above the cap and that
El Paso must reimburse Case for those payments. In January
2006, these rulings were upheld on appeal by the U.S. Court
of Appeals for the 6th Circuit. We will proceed with a
trial on the merits with regard to the issues of whether the cap
is enforceable and what degree of benefits have actually vested.
Until this is resolved, El Paso will indemnify Case for any
payments Case makes above the cap, which are currently about
$1.8 million per month. We continue to defend the action
and have filed for approval by the trial court various
amendments to the medical benefit plans which would allow us to
deliver the benefits to plan participants in a more cost
effective manner. Although it is uncertain what plan amendments
will ultimately be approved, the approval of plan amendments
could reduce our overall costs
12
and, as a result, could reduce our recorded obligation. We have
established an accrual for this matter which we believe is
adequate.
Natural Gas Commodities Litigation. Beginning
in August 2003, several lawsuits have been filed against
El Paso Marketing L.P. (EPM) that allege 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. The first cases
have been consolidated in federal court in New York for all
pre-trial purposes and are styled In re: Gas Commodity
Litigation. In September 2005, the court certified the class
to include all persons who purchased or sold NYMEX natural gas
futures between January 1, 2000 and December 31, 2002.
A settlement has been finalized with the plaintiffs and funded
subject to final court approval. The second set of cases,
involving similar allegations on behalf of commercial and
residential customers, were transferred to a multi-district
litigation proceeding (MDL) in the U.S. District Court
for Nevada, In re: Western States Wholesale Natural Gas
Antitrust Litigation, dismissed and have been appealed. The
third set of cases also involve similar allegations on behalf of
certain purchasers of natural gas. These include purported class
action lawsuits styled Leggett, et al. v. Duke
Energy Corporation, et al. (filed in Chancery Court of
Tennessee in January 2005); Ever-Bloom Inc. v. AEP
Energy Services Inc., et al. (filed in federal court
for the Eastern District of California in June 2005);
Farmland Industries, Inc. v. Oneok Inc. (filed in
state court in Wyandotte County, Kansas in July 2005);
Learjet, Inc. v. Oneok Inc., (filed in state court
in Wyandotte County, Kansas in September 2005); Breckenridge,
et al. v. Oneok Inc., et al. (filed in state
court in Denver County, Colorado in May 2006), Missouri
Public Service Commission v. El Paso Corporation,
et al. (filed in the circuit court of Jackson County,
Missouri at Kansas City in October 2006), Arandell,
et al. v. Xcel Energy, et al. (filed in the
circuit court of Dane County, Wisconsin in December
2006) and Heartland, et al. v. Oneok Inc.,
et al. (filed in the circuit court of Buchanan County,
Missouri in March 2007). The Leggett and Farmland
cases have been dismissed, subject to appeal. The
Arandell and Missouri Public Service cases have
been removed to federal court. The Heartland case has
only recently been filed. The remaining cases have all been
transferred to the MDL proceeding. Similar motions to dismiss
have either been filed or are anticipated to be filed in these
cases as well. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.
Gas Measurement Cases. A number of our
subsidiaries were named defendants in actions that generally
allege mismeasurement of natural gas volumes
and/or
heating content resulting in the underpayment of royalties. The
first set of cases was filed in 1997 by an individual under the
False Claims Act, which has been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation,
U.S. District Court for the District of Wyoming). These
complaints allege an industry-wide conspiracy to underreport the
heating value as well as the volumes of the natural gas produced
from federal and Native American lands. In May 2005, a
representative appointed by the court issued a recommendation to
dismiss most of the actions. In October 2006, the
U.S. District Judge issued an order dismissing all
mismeasurement claims against all defendants. An appeal has been
filed.
Similar allegations were filed in a set of actions initiated in
1999 in Will Price, et al. v. Gas Pipelines and
Their Predecessors, et al., in the District Court of
Stevens County, Kansas. The plaintiffs currently seek
certification of a class of royalty owners in wells on
non-federal and non-Native American lands in Kansas, Wyoming and
Colorado. Motions for class certification have been briefed and
argued in the proceedings and the parties are awaiting the
courts ruling. The plaintiff seeks an unspecified amount
of monetary damages in the form of additional royalty payments
(along with interest, expenses and punitive damages) and
injunctive relief with regard to future gas measurement
practices. Our costs and legal exposure related to these
lawsuits and claim are not currently determinable.
MTBE. Certain of our subsidiaries used the
gasoline additive methyl tertiary-butyl ether (MTBE) in some of
their gasoline. Certain subsidiaries have also produced, bought,
sold and distributed MTBE. A number of lawsuits have been filed
throughout the U.S. regarding MTBEs potential impact
on water supplies. Some of our subsidiaries are among the
defendants in 78 such lawsuits. These suits have been
consolidated for pre-trial purposes in multi- district
litigation in the U.S. District Court for the Southern
District of New York. The plaintiffs, certain state attorneys
general, various water districts and a limited number of
individual water customers, generally seek remediation of their
groundwater, prevention of future contamination, damages,
punitive damages, attorneys fees and court costs. Among
other allegations, plaintiffs assert that gasoline containing
MTBE is a defective product and that defendant refiners are
liable in proportion to their market share. The court has
ordered that the parties engage in
13
mediation proceedings to attempt to settle the case. Our costs
and legal exposure related to these lawsuits are not currently
determinable.
Government
Investigations and Inquiries
Reserve Revisions. In March 2004, we received
a subpoena from the SEC requesting documents relating to our
December 31, 2003 natural gas and oil reserve revisions. We
continue to cooperate with the SEC in its investigation related
to such reserve revisions.
Iraq Oil Sales. Several government agencies
have been investigating The Coastal Corporations and
El Pasos purchases of crude oil from Iraq under the
United Nations Oil for Food Program. These agencies
include the U.S. Attorney for the Southern District of New
York (SDNY), the SEC and the Office of Foreign Assets Control
(OFAC). In February 2007, we entered into agreements with the
SDNY, SEC , and OFAC to resolve their pending investigations of
our participation in the Oil for Food Program. Pursuant to those
agreements we paid approximately $8 million, with
approximately $6 million intended to be ultimately
transferred to a humanitarian fund for the benefit of the Iraqi
people.
Other Government Investigations. We continue
to provide information and cooperate with the inquiry or
investigation of the U.S. Attorney and the SEC in response
to requests for information regarding price reporting of
transactional data to the energy trade press and the hedges of
our natural gas production.
Other
Contingencies
EPNG Rate Case. In June 2005, EPNG filed a
rate case with the FERC proposing an increase in revenues of
10.6 percent or $56 million annually over current
tariff rates, new services and revisions to certain terms and
conditions of existing services. On January 1, 2006, the
rates became effective, subject to refund. In March 2006, the
FERC issued an order that generally approved our proposed new
services, which were implemented on June 1, 2006. In
December 2006, EPNG filed settlement of this rate case with the
FERC. The settlement provides benefits for both EPNG and its
customers for a three-year period ending December 31, 2008.
Only one party in the rate case contested the settlement. The
administrative law judge has certified the settlement to the
FERC finding that the settlement could be approved for all
parties or in the alternative that the contesting party could be
severed from the settlement. We have reserved sufficient amounts
to meet EPNGs refund obligations under the settlement.
Such refunds will be payable within 120 days after approval
by the FERC.
Iraq Imports. In December 2005, the Ministry
of Oil for the State Oil Marketing Organization of Iraq (SOMO)
sent an invoice to one of our subsidiaries with regard to
shipments of crude oil that SOMO alleged were purchased and paid
for by Coastal in 1990. The invoice requests an additional
$144 million for such shipments, along with an allegation
of an undefined amount of interest. The invoice appears to be
associated with cargoes that Coastal had purchased just before
the 1990 invasion of Kuwait by Iraq. We have requested
additional information from SOMO to further assist in our
evaluation of the invoice and the underlying facts. In addition,
we are evaluating our legal defenses, including applicable
statute of limitation periods.
Navajo Nation. Approximately 900 looped
pipeline miles of the north mainline of our EPNG pipeline system
are located on lands held in trust by the United States for the
benefit of the Navajo Nation. Our
rights-of-way
on lands crossing the Navajo Nation are the subject of a pending
renewal application filed in 2005 with the Department of the
Interiors Bureau of Indian Affairs. An interim agreement
with the Navajo Nation expired at the end of December 2006.
Negotiations on the terms of the long-term agreement are
continuing. In addition, we continue to preserve other legal,
regulatory and legislative alternatives, which includes
continuing to pursue our application with the Department of the
Interior for renewal of our
rights-of-way
on Navajo Nation lands. It is uncertain whether our negotiation,
or other alternatives, will be successful, or if successful,
what the ultimate cost will be of obtaining the
rights-of-way
and whether we will be able to recover these costs in our rates.
In addition to the above legal proceedings, governmental
proceedings, and other contingent matters, we and our
subsidiaries and affiliates are named defendants in numerous
lawsuits and governmental proceedings that arise in the ordinary
course of our business. There are also other regulatory rules
and orders in various stages of adoption, review
and/or
implementation. For each of our outstanding legal and other
contingent matters, we evaluate the
14
merits of the case, 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. However, it
is possible 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 March 31, 2007, we had
approximately $531 million accrued, net of related
insurance receivables, for outstanding legal and other
contingent matters.
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
on the environment of the disposal or release of specified
substances at current and former operating sites. As of
March 31, 2007, we have accrued approximately
$295 million, which has not been reduced by
$31 million for amounts to be paid directly under
government sponsored programs. Our accrual includes
approximately $286 million for expected remediation costs
and associated onsite, offsite and groundwater technical studies
and approximately $9 million for related environmental
legal costs. Of the $295 million accrual, $28 million
was reserved for facilities we currently operate and
$267 million was reserved for non-operating sites
(facilities that are shut down or have been sold) and Superfund
sites.
Our reserve estimates range from approximately $295 million
to approximately $516 million. Our accrual represents a
combination of two estimation methodologies. First, where the
most likely outcome can be reasonably estimated, that cost has
been accrued ($23 million). Second, where the most likely
outcome cannot be estimated, a range of costs is established
($272 million to $493 million) and if no one amount in
that range is more likely than any other, the lower end of the
expected range has been accrued. Our environmental remediation
projects are in various stages of completion. Our recorded
liabilities reflect our current estimates of amounts we will
expend to remediate these sites. 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:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2007
|
|
Sites
|
|
Expected
|
|
|
High
|
|
|
|
(In millions)
|
|
|
Operating
|
|
$
|
28
|
|
|
$
|
34
|
|
Non-operating
|
|
|
233
|
|
|
|
423
|
|
Superfund
|
|
|
34
|
|
|
|
59
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
295
|
|
|
$
|
516
|
|
|
|
|
|
|
|
|
|
|
Below is a reconciliation of our accrued liability from
January 1, 2007 to March 31, 2007 (in millions):
|
|
|
|
|
Balance as of January 1, 2007
|
|
$
|
314
|
|
Additions/adjustments for
remediation activities
|
|
|
8
|
|
Payments for remediation activities
|
|
|
(27
|
)
|
|
|
|
|
|
Balance as of March 31, 2007
|
|
$
|
295
|
|
|
|
|
|
|
For the remainder of 2007, we estimate that our total
remediation expenditures will be approximately $62 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 $26 million in the
aggregate for the remainder of 2007 through 2011. These
expenditures primarily relate to compliance with clean air
regulations.
CERCLA Matters. We have received notice that
we could be designated, or have been asked for information to
determine whether we could be designated, as a Potentially
Responsible Party (PRP) with respect to 50 active
15
sites under the CERCLA or state equivalents. We have sought to
resolve our liability as a PRP at these sites through
indemnification by third-parties and settlements, which provide
for payment of our allocable share of remediation costs. As of
March 31, 2007, we have estimated our share of the
remediation costs at these sites to be between $34 million
and $59 million. Because the
clean-up
costs are estimates and are subject to revision as more
information becomes available about the extent of remediation
required, and in some cases we have asserted a defense to any
liability, our estimates could change. Moreover, liability under
the federal CERCLA statute is joint and several, meaning that we
could be required to pay in excess of our pro rata share of
remediation costs. Our understanding of the financial strength
of other PRPs has been considered, where appropriate, in
estimating our liabilities. Accruals for these issues are
included in the previously indicated estimates for Superfund
sites.
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 Indemnifications
We are involved in various joint ventures and other ownership
arrangements that sometimes require additional financial support
that results in the issuance of financial and performance
guarantees. We also periodically provide indemnification
arrangements related to assets or businesses we have sold. These
arrangements include, but are not limited to, indemnification
for income taxes, the resolution of existing disputes,
environmental matters, and necessary expenditures to ensure the
safety and integrity of the assets sold.
Our potential exposure under the guarantee and indemnification
agreements can range from a specified amount to an unlimited
dollar amount, depending on the nature of the claim and the
particular transaction. For those arrangements with a specified
dollar amount, we have a maximum stated value of approximately
$811 million, for which we are indemnified by third parties
for $15 million. These amounts exclude guarantees for which
we have issued related letters of credit discussed in
Note 6. Included in the above maximum stated value is
approximately $440 million related to indemnification
arrangements associated with the sale of ANR, and related
operations and approximately $120 million related to tax
matters, related interest and other indemnifications and
guarantees arising out of the sale of our Macae power facility.
As of March 31, 2007, we have recorded obligations of
$85 million related to our guarantees and indemnification
arrangements, of which $11 million is related to ANR and
related assets and Macae. We are unable to estimate a maximum
exposure for our guarantee and indemnification agreements that
do not provide for limits on the amount of future payments under
the agreement due to the uncertainty of these exposures.
In addition to the exposures described above, a trial court has
ruled, which was upheld on appeal, that we are required to
indemnify a third party for benefits being paid to a closed
group of retirees of one of our former subsidiaries. We have a
liability of approximately $364 million associated with our
estimated exposure under this matter as of March 31, 2007.
For a further discussion of this matter, see Retiree Medical
Benefits Matters above.
16
The components of net benefit cost for our pension and
postretirement benefit plans for the quarters ended
March 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Service cost
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
|
|
Interest cost
|
|
|
30
|
|
|
|
29
|
|
|
|
6
|
|
|
|
7
|
|
Expected return on plan assets
|
|
|
(45
|
)
|
|
|
(44
|
)
|
|
|
(4
|
)
|
|
|
(4
|
)
|
Amortization of net actuarial loss
|
|
|
10
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Amortization of prior service
cost(1)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Special termination
benefits(2)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit cost
|
|
$
|
5
|
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As permitted, the amortization of
any prior service cost is determined using a straight-line
amortization of the cost over the average remaining service
period of employees expected to receive benefits under the plan.
|
|
(2) |
|
Relates to providing enhanced
benefits to former ANR employees, which is included in
discontinued operations in our income statement.
|
In December 2006, we adopted the recognition provisions of
SFAS No. 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement
Plans an amendment of FASB
Statements No. 87, 88, 106 and 132(R) and began
reflecting assets and liabilities related to our pension and
other postretirement benefit plans based on their funded or
unfunded status and reclassifying all actuarial deferrals as a
component of accumulated other comprehensive income. In March
2007, the FERC issued guidance requiring regulated pipeline
companies to recognize a regulatory asset or liability for the
funded status asset or liability that would otherwise be
recorded in accumulated other comprehensive income under
SFAS No. 158, if it is probable that amounts
calculated on the same basis as SFAS No. 106,
Employers Accounting for Postretirement Benefits Other
Than Pensions would be included in rates in future periods.
Upon adoption of this FERC guidance, we reclassified
approximately $4 million from the beginning balance of
accumulated other comprehensive income to other non-current
assets and liabilities on our balance sheet.
During the three months ended March 31, 2007 and 2006, we
made $8 million and $11 million of cash contributions
to our Supplemental Benefits Plan and other postretirement
benefit plans. We also made $2 million in cash
contributions to our pension plans for the quarter ended
March 31, 2007. We expect to contribute an additional
$4 million to the Supplemental Benefits Plan and
$27 million to our other postretirement benefit plans for
the remainder of 2007. Contributions to our pension plans will
be approximately $1 million for the remainder of 2007.
Dividends. The table below shows the amount of
dividends paid and declared (in millions, except per share
amounts).
|
|
|
|
|
|
|
|
|
Convertible
|
|
|
Common Stock
|
|
Preferred Stock
|
|
|
($0.04/Share)
|
|
(4.99%/Year)
|
|
Amount paid through March 31,
2007
|
|
$28
|
|
$9
|
Amount paid in April 2007
|
|
$27
|
|
$9
|
Declared subsequent to
March 31, 2007:
|
|
|
|
|
Date of declaration
|
|
April 3, 2007
|
|
April 3, 2007
|
Date payable
|
|
July 2, 2007
|
|
July 2, 2007
|
Payable to shareholders on record
|
|
June 1, 2007
|
|
June 15, 2007
|
17
Dividends on our common stock are treated as a reduction of
additional
paid-in-capital
since we currently have an accumulated deficit. We expect
dividends paid on our common and preferred stock in 2007 will be
taxable to our stockholders because we anticipate they will be
paid out of current or accumulated earnings and profits for tax
purposes.
The terms of our 750,000 outstanding shares of
4.99% convertible preferred stock prohibit the payment of
dividends on our common stock unless we have paid or set aside
for payment all accumulated and unpaid dividends on such
preferred stock for all preceding dividend periods. In addition,
although our credit facilities do not contain any direct
restriction on the payment of dividends, dividends are included
as a fixed charge in the calculation of our fixed charge
coverage ratio under our credit facilities. If our fixed charge
ratio were to exceed the permitted maximum level, our ability to
pay additional dividends would be restricted.
|
|
10.
|
Business
Segment Information
|
As of March 31, 2007, our business consists of Pipelines,
Exploration and Production, Marketing and Power segments. We
have reclassified certain operations as discontinued operations
for all periods presented (see Notes 1 and 2). 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.
Our corporate operations include our general and administrative
functions, as well as other miscellaneous businesses and various
other contracts and assets, all of which are immaterial. A
further discussion of each segment follows.
Pipelines. Provides natural gas transmission,
storage, and related services, primarily in the United States.
As of March 31, 2007, we conducted our activities primarily
through seven wholly owned and four partially owned interstate
transmission systems along with two underground natural gas
storage entities and an LNG terminalling facility.
Exploration and Production. Engages in the
exploration for and the acquisition, development and production
of natural gas, oil and NGL, primarily in the United States,
Brazil and Egypt.
Marketing. Focuses on marketing and managing
the price risks associated with our natural gas and oil
production as well as the management of our remaining historical
trading portfolio.
Power. Focuses primarily on managing the risks
associated with our remaining international power assets,
primarily in Brazil, Asia and Central America. We continue to
pursue the sale of our remaining international power assets.
Our management uses earnings before interest expense and income
taxes (EBIT) to assess the operating results and effectiveness
of our business segments which consist of both consolidated
businesses as well as substantial investments in unconsolidated
affiliates. We believe EBIT is useful to our investors because
it allows them to more effectively evaluate our operating
performance using the same performance measure analyzed
internally by our management. We define EBIT as net income or
loss adjusted for (i) items that do not impact our income
or loss from continuing operations, such as extraordinary items,
discontinued operations and the impact of accounting changes,
(ii) income taxes, (iii) interest and debt expense and
(iv) preferred dividends. Also, we exclude interest and
debt expense so that investors may evaluate our operating
results without regard to our financing methods or capital
structure. EBIT may not be comparable to measures used by other
companies. Additionally, EBIT should be considered in
conjunction with net income and other performance measures such
as operating income or operating cash flow. Below is a
reconciliation of our EBIT to our income (loss) from continuing
operations for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Segment EBIT
|
|
$
|
426
|
|
|
$
|
756
|
|
Corporate and other
|
|
|
(210
|
)
|
|
|
|
|
Interest and debt expense
|
|
|
(283
|
)
|
|
|
(331
|
)
|
Income taxes
|
|
|
19
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations
|
|
$
|
(48
|
)
|
|
$
|
301
|
|
|
|
|
|
|
|
|
|
|
18
The following table reflects our segment results for each of the
quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
|
|
|
|
Pipelines
|
|
|
Production
|
|
|
Marketing
|
|
|
Power
|
|
|
and
Other(1)
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from external customers
|
|
$
|
631
|
|
|
$
|
220
|
(2)
|
|
$
|
159
|
|
|
$
|
|
|
|
$
|
12
|
|
|
$
|
1,022
|
|
Intersegment revenue
|
|
|
13
|
|
|
|
285
|
(2)
|
|
|
(294
|
)
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
Operation and maintenance
|
|
|
161
|
|
|
|
110
|
|
|
|
|
|
|
|
4
|
|
|
|
26
|
|
|
|
301
|
|
Depreciation, depletion, and
amortization
|
|
|
94
|
|
|
|
170
|
|
|
|
1
|
|
|
|
|
|
|
|
6
|
|
|
|
271
|
|
Earnings (losses) from
unconsolidated affiliates
|
|
|
26
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
11
|
|
|
|
1
|
|
|
|
37
|
|
EBIT
|
|
|
364
|
|
|
|
179
|
|
|
|
(135
|
)
|
|
|
18
|
|
|
|
(210
|
)
|
|
|
216
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from external customers
|
|
$
|
629
|
|
|
$
|
81
|
(2)
|
|
$
|
598
|
|
|
$
|
1
|
|
|
$
|
28
|
|
|
$
|
1,337
|
|
Intersegment revenue
|
|
|
14
|
|
|
|
385
|
(2)
|
|
|
(393
|
)
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
Operation and maintenance
|
|
|
168
|
|
|
|
88
|
|
|
|
3
|
|
|
|
14
|
|
|
|
12
|
|
|
|
285
|
|
Depreciation, depletion, and
amortization
|
|
|
93
|
|
|
|
146
|
|
|
|
1
|
|
|
|
|
|
|
|
10
|
|
|
|
250
|
|
Earnings (losses) from
unconsolidated affiliates
|
|
|
16
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
|
|
(1
|
)
|
|
|
29
|
|
EBIT
|
|
|
346
|
|
|
|
199
|
|
|
|
208
|
|
|
|
3
|
|
|
|
|
|
|
|
756
|
|
|
|
|
(1) |
|
Includes eliminations of
intercompany transactions. Our intersegment revenues, along with
our intersegment operating expenses, were incurred in the normal
course of business between our operating segments. During the
quarters ended March 31, 2007 and 2006, we recorded an
intersegment revenue elimination of $5 million and
$6 million.
|
|
(2) |
|
Revenues from external customers
include gains and losses related to our hedging of price risk
associated with our natural gas and oil production. Intersegment
revenues represent sales to our Marketing segment, which is
responsible for marketing our production.
|
Total assets by segment are presented below:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Pipelines
|
|
$
|
13,171
|
|
|
$
|
13,105
|
|
Exploration and Production
|
|
|
6,422
|
|
|
|
6,262
|
|
Marketing and Trading
|
|
|
727
|
|
|
|
1,143
|
|
Power
|
|
|
630
|
|
|
|
618
|
|
|
|
|
|
|
|
|
|
|
Total segment assets
|
|
|
20,950
|
|
|
|
21,128
|
|
Corporate
|
|
|
1,713
|
|
|
|
2,000
|
|
Discontinued operations
|
|
|
|
|
|
|
4,133
|
|
|
|
|
|
|
|
|
|
|
Total consolidated assets
|
|
$
|
22,663
|
|
|
$
|
27,261
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
|
Investments
in, Earnings from and Transactions with Unconsolidated
Affiliates
|
We hold investments in unconsolidated affiliates which are
accounted for using the equity method of accounting. Our income
statement typically reflects (i) our share of net earnings
directly attributable to these unconsolidated affiliates, and
(ii) impairments and other adjustments recorded by us.
During the quarters ended March 31, 2007 and 2006, we
received distributions and dividends of $74 million and
$36 million, which includes less than $1 million of
returns of capital, from our investments. The information below
related to our unconsolidated affiliates includes (i) our
net investment and earnings (losses) we recorded from these
investments, (ii) summarized
19
financial information of our proportionate share of these
investments, and (iii) revenues and charges with our
unconsolidated affiliates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
|
|
|
|
|
|
|
(Losses) from
|
|
|
|
|
|
|
|
|
|
Unconsolidated
|
|
|
|
|
|
|
|
|
|
Affiliates
|
|
Net investment and earnings
(losses)
|
|
Investment
|
|
|
Quarter Ended
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four
Star(1)
|
|
$
|
703
|
|
|
$
|
723
|
|
|
$
|
(1
|
)
|
|
$
|
7
|
|
Citrus
|
|
|
571
|
|
|
|
597
|
|
|
|
22
|
|
|
|
10
|
|
Other
|
|
|
38
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
Foreign:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bolivia to Brazil Pipeline
|
|
|
108
|
|
|
|
105
|
|
|
|
3
|
|
|
|
1
|
|
Manaus/Rio
Negro(2)
|
|
|
93
|
|
|
|
96
|
|
|
|
4
|
|
|
|
6
|
|
Porto
Velho(3)
|
|
|
(32
|
)
|
|
|
(34
|
)
|
|
|
2
|
|
|
|
(3
|
)
|
Asian and Central American
Investments(3)(4)
|
|
|
27
|
|
|
|
27
|
|
|
|
|
|
|
|
1
|
|
Other(3)
|
|
|
163
|
|
|
|
157
|
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,671
|
|
|
$
|
1,707
|
|
|
$
|
37
|
|
|
$
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amortization of our purchase cost
in excess of the underlying net assets of Four Star was
$14 million during each of the quarters ended
March 31, 2007 and 2006. For a further discussion, see our
2006 Annual Report on
Form 10-K.
|
|
(2) |
|
We will transfer ownership of these
plants to the power purchaser in January 2008.
|
|
(3) |
|
As of March 31, 2007 and
December 31, 2006, we had outstanding advances and notes
receivable of $381 million and $380 million related to
our foreign investments of which $360 million and
$350 million related to our investment in Porto Velho. We
recognized interest income on these outstanding advances and
notes receivable of approximately $12 million and
$11 million for the three months ended March 31, 2007
and 2006.
|
|
(4) |
|
We have received approval from our
Board of Directors to sell our interest in these investments,
all of which are expected to be sold in 2007.
|
|
|
|
|
|
|
|
|
|
Summarized financial
information
|
|
Quarter Ended March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Operating results data:
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
189
|
|
|
$
|
305
|
|
Operating expenses
|
|
|
111
|
|
|
|
263
|
|
Income (loss) from continuing
operations
|
|
|
51
|
|
|
|
(19
|
)
|
Net income
(loss)(1)
|
|
|
51
|
|
|
|
(19
|
)
|
|
|
|
(1) |
|
Includes net income of
$5 million for each of the quarters ended March 31,
2007 and 2006, related to our proportionate share of affiliates
in which we hold greater than a 50 percent interest.
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Revenues and charges with
unconsolidated affiliates
|
|
March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Operating
revenue(1)
|
|
$
|
1
|
|
|
$
|
34
|
|
Other income
|
|
|
1
|
|
|
|
2
|
|
Interest income
|
|
|
12
|
|
|
|
11
|
|
|
|
|
(1) |
|
Decrease primarily due to the sale
of investments in our Power segment.
|
20
Matters
that Could Impact Our Investments
The following information is a discussion of significant matters
that could impact certain of our investments.
Porto Velho. As of March 31, 2007, our
total investment (including advances to the project) and
guarantees related to this project was approximately
$329 million. The state-owned facility that purchases power
generated by the facility in Brazil has approached us with the
opportunity to sell them our interest in this power plant.
Although we currently have no indications of an impairment of
our investment, as we evaluate this opportunity, we could be
required to record a loss based on the value we may receive. In
December 2006, the Brazilian tax authorities assessed a
$30 million fine against the Porto Velho power project for
allegedly not filing the proper tax forms related to the
consumption of fuel by the power facility under its power
purchase agreement. We believe this claim by the tax authority
is without merit.
Asian and Central American power
investments. As of March 31, 2007, our total
investment (including advances to the projects) and guarantees
related to these projects was approximately $93 million. We
are in the process of selling these assets. Any changes in the
political and economic conditions could negatively impact the
amount of net proceeds we expect to receive upon their sale,
which may result in additional impairments.
Investment in Bolivia. We own an
8 percent interest in the Bolivia to Brazil pipeline. As of
March 31, 2007, our total investment and guarantees related
to this pipeline project was approximately $120 million, of
which the Bolivian portion was $3 million. In 2006, the
Bolivian government announced a decree significantly increasing
its interest in and control over Bolivias oil and gas
assets. We continue to monitor and evaluate, together with our
partners, the potential commercial impact that recent political
events in Bolivia could have on the Bolivia to Brazil pipeline.
As new information becomes available or future material
developments arise, we may be required to record an impairment
of our investment.
Investment in Argentina. We own an approximate
22 percent interest in the Argentina to Chile pipeline. As
of March 31, 2007, our total investment in this pipeline
project was approximately $24 million. In July 2006, the
Ministry of Economy and Production in Argentina issued a decree
that significantly increases the export taxes on natural gas. We
continue to evaluate, together with our partners, the potential
commercial impact that this decree could have on the Argentina
to Chile pipeline. As new information becomes available or
future material developments arise, we may be required to record
an impairment of our investment.
21
|
|
Item 2.
|
Managements
Discussion And Analysis Of Financial Condition And Results Of
Operations
|
The information contained in Item 2 updates, and you should
read it in conjunction with, information disclosed in our 2006
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
Financial Update. During the first three
months of 2007, our pipeline operations continued to provide a
strong base of earnings and cash flow and make progress on
expansion projects. Our exploration and production business
continued to execute on its drilling programs resulting in
higher production levels in the first quarter of 2007,
consistent with the levels originally expected for the quarter
and higher when compared to the same period in 2006. During the
first quarter of 2007, our financial results were also marked by
several significant events including the completion of the sale
of ANR and related assets in which we recorded a gain of
approximately $651 million (net of taxes of
$356 million), and the repurchase of approximately
$3.5 billion of debt on which we recorded a pre-tax loss of
$201 million due to the extinguishment of certain of these
obligations.
We have strengthened our credit metrics in 2007 through various
financing activities including the repurchases mentioned above
as well as refinancing a portion of EPNG and SNGs debt
that provides us with a lower cost of capital and an investment
grade covenant package on that debt. Additionally, our credit
ratings were upgraded by both Moodys and
Standard & Poors and Fitch Ratings initiated
coverage on El Paso in the first quarter of 2007. For
further information on these debt repurchases and changes to our
credit ratings, see our Liquidity and Capital Resources
discussion.
What to Expect Going Forward. In our pipeline
operations, we will continue with our expansion projects in our
primary growth areas and anticipate that our remaining pipeline
operations will continue to provide strong operating results
throughout the year based on the current levels of contracted
capacity, continued success in re-contracting, expansion plans
in our market and supply areas and the status of rate and
regulatory actions. As previously announced, we are pursuing the
formation of a master limited partnership in 2007 to enhance the
value and financial flexibility of our pipeline assets and
provide a lower-cost source of capital for new projects.
In our exploration and production business, we will continue to
seek to create value through a disciplined and balanced capital
investment program, through active management of the cost of
production services, portfolio management and a focus on
delivering reserves and volumes at reasonable finding and
operating costs. Our future financial results in this business
will be primarily dependent on continued successful execution of
our drilling programs. These results may also be impacted by
changes in commodity prices to the extent our anticipated
natural gas and oil production is unhedged. We have currently
hedged a substantial portion of our remaining anticipated 2007
natural gas production and a portion of our anticipated natural
gas production for 2008 and forward and continue to evaluate
opportunities to effectively manage our commodity price risk.
22
Segment
Results
Below are our results of operations (as measured by earnings
before interest expense and income taxes (EBIT)) by segment. Our
business segments consist of our Pipelines, Exploration and
Production, Marketing and Power segments. These segments are
managed separately, provide a variety of energy products and
services, and require different technology and marketing
strategies. Our corporate activities include our general and
administrative functions, as well as other miscellaneous
businesses, contracts and assets, all of which are immaterial.
Our management uses EBIT to assess the operating results and
effectiveness of our business segments, which consist of both
consolidated businesses as well as substantial investments in
unconsolidated affiliates. We believe EBIT is useful to our
investors because it allows them to more effectively evaluate
our operating performance using the same performance measure
analyzed internally by our management. We define EBIT as net
income or loss adjusted for (i) items that do not impact
our income or loss from continuing operations, such as
extraordinary items, discontinued operations and the impact of
accounting changes, (ii) income taxes, (iii) interest
and debt expense and (iv) preferred dividends. Also, we
exclude interest and debt expense so that investors may evaluate
our operating results without regard to our financing methods or
capital structure. EBIT may not be comparable to measures used
by other companies. Additionally, EBIT should be considered in
conjunction with net income and other performance measures such
as operating income or operating cash flow. Below is a
reconciliation of our EBIT (by segment) to our consolidated net
income for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Segment
|
|
|
|
|
|
|
|
|
Pipelines
|
|
$
|
364
|
|
|
$
|
346
|
|
Exploration and Production
|
|
|
179
|
|
|
|
199
|
|
Marketing
|
|
|
(135
|
)
|
|
|
208
|
|
Power
|
|
|
18
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Segment EBIT
|
|
|
426
|
|
|
|
756
|
|
Corporate and other
|
|
|
(210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated EBIT
|
|
|
216
|
|
|
|
756
|
|
Interest and debt expense
|
|
|
(283
|
)
|
|
|
(331
|
)
|
Income taxes
|
|
|
19
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations
|
|
|
(48
|
)
|
|
|
301
|
|
Discontinued operations, net of
income taxes
|
|
|
677
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
629
|
|
|
$
|
356
|
|
|
|
|
|
|
|
|
|
|
23
Pipelines
Segment
Operating Results. Below are the operating
results for our Pipelines segment as well as a discussion of
factors impacting EBIT for the periods ending March 31,
2007 and 2006, or that could potentially impact EBIT in future
periods.
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except volume amounts)
|
|
|
Operating revenues
|
|
$
|
644
|
|
|
$
|
643
|
|
Operating expenses
|
|
|
(320
|
)
|
|
|
(322
|
)
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
324
|
|
|
|
321
|
|
Other income
|
|
|
40
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
EBIT
|
|
$
|
364
|
|
|
$
|
346
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes
(BBtu/d)(1)
|
|
|
18,040
|
|
|
|
16,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Throughput volumes include volumes
associated with our proportionate share of unconsolidated
affiliates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31,
|
|
|
|
Variance
|
|
|
|
Revenue
|
|
|
Expense
|
|
|
Other
|
|
|
EBIT
|
|
|
|
Impact
|
|
|
Impact
|
|
|
Impact
|
|
|
Impact
|
|
|
|
Favorable/(Unfavorable)
|
|
|
|
(In millions)
|
|
|
Expansions
|
|
$
|
8
|
|
|
$
|
(1
|
)
|
|
$
|
2
|
|
|
$
|
9
|
|
Lower reservation and usage
revenues
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Operational gas and revaluations
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
(10
|
)
|
Hurricanes Katrina and Rita
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
Gain on sale of asset in 2007
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
Equity earnings from Citrus
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
12
|
|
Other(1)
|
|
|
(1
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on EBIT
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
15
|
|
|
$
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of individually
insignificant items on several of our pipeline systems.
|
Expansions. During the quarter ended
March 31, 2007, our reservation revenues and throughput
volumes were higher than the same period in 2006 primarily due
to the Elba Island LNG and Piceance Basin expansion projects
completed during the first quarter of 2006.
We have several expansion projects approved by the FERC in
various stages of completion including our Louisiana Deepwater
Link, Triple-T Extension, Essex Middlesex Project, Northeast
Connexion New England and Cypress Expansion
projects. In May 2007, we placed the Cypress pipeline into
service which is estimated to have an annual EBIT contribution
of approximately $32 million.
Lower Reservation and Usage Revenues. During
the quarter ended March 31, 2007, our overall reservation
and usage revenues were lower than the same period in 2006.
Usage revenues decreased in 2007 due to reduced activity under
certain interruptible services primarily on our TGP system and a
higher provision for rate refunds on our EPNG system in 2007.
However, our EBIT was favorably impacted in 2007 due to higher
volumes on our pipeline systems, mainly the CIG system, due to
cold weather and transportation services to new power plants.
Additionally, CIG experienced increased revenues due to higher
rates that went into effect in October 2006.
Operational Gas and Revaluations. Our net gas
imbalances and other gas owed to customers are revalued each
period. During the quarter ended March 31, 2007, our EBIT
decreased from the same period in 2006 due to these
revaluations. During the first quarter of 2007, natural gas
prices increased unfavorably impacting our results.
Additionally, natural gas prices decreased during the first
quarter of 2006 favorably impacting our results during
24
that period. We anticipate that the overall activity in this
area will continue to vary based on factors such as regulatory
actions, some of which have already been implemented, the
efficiency of our pipeline operations, natural gas prices and
other factors.
Hurricanes Katrina and Rita. During the first
quarter of 2007, we incurred lower operation and maintenance
expenses to repair damage caused by Hurricanes Katrina and Rita
as compared to the same period in 2006. For a further discussion
of the impact of these hurricanes on our capital expenditures,
see Liquidity and Capital Resources.
Gain on sale of asset. In February 2007,
Tennessee Gas Pipeline Company completed the sale of a lateral
for approximately $35 million and recorded a pretax gain on
the sale of approximately $7 million.
Equity earnings from Citrus. Our equity
earnings increased by approximately $12 million,
$8 million of which was due to a favorable settlement of
litigation brought against Spectra LNG Sales (formerly Duke
Energy LNG Sales, Inc.) related to the wrongful termination of a
gas supply contract.
Regulatory Matters/Rate Cases. Our pipeline
systems periodically file for changes in their rates, which are
subject to the approval of the FERC. Changes in rates and other
tariff provisions resulting from these regulatory proceedings
have the potential to positively or negatively impact our
profitability.
|
|
|
|
|
EPNG In December 2006, EPNG filed a
settlement of its rate case with the FERC providing benefits for
both EPNG and its customers for a three year period ending
December 31, 2008. Under the terms of the settlement, EPNG
is required to file a new rate case effective January 1,
2009. EPNGs recorded income amounts currently reflect
their proposed rates and we have reserved sufficient amounts to
meet EPNGs refund obligations under this settlement. For a
further discussion, see Item 1, Financial Statements,
Note 7.
|
|
|
|
Mojave Pipeline (MPC) In February 2007, as
required by its prior rate case settlement, MPC filed with the
FERC a general rate case proposing a 33 percent decrease in
its base tariff rates resulting from a variety of factors,
including a decline in rate base and various changes in rate
design since the last rate case. No new services were proposed.
We anticipate a decrease in revenues of approximately
$13 million annually due to Mojaves reduced base
rates. The new base rates were effective March 1, 2007 and
are subject to further adjustment upon the outcome of the
hearing.
|
25
Exploration
and Production Segment
Overview
and Strategy
Our Exploration and Production segment conducts our natural gas
and oil exploration and production activities. Our profitability
and performance in this segment are driven by the ability to
locate and develop economic natural gas and oil reserves and
extract those reserves with 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 domestic
natural gas and oil reserve portfolio blends slower decline
rate, typically longer lived assets in our Onshore region, with
steeper decline rate, shorter lived assets in our Texas Gulf
Coast and Gulf of Mexico Shelf and south Louisiana regions. We
believe the combination of our assets in these regions provides
significant near-term cash flows while providing consistent
opportunities for competitive investment returns. In addition,
our international activities in Brazil and Egypt provide
opportunity for additional future reserve additions and longer
term cash flows. For a further discussion of our business and
strategy, see our 2006 Annual Report on
Form 10-K.
Operating
Results for the Quarter Ended March 31, 2007
Average Daily Production. Our average daily
production for the three months ended March 31, 2007, was
750 MMcfe/d (excluding 70 MMcfe/d from our equity
investment in Four Star). Our average daily production levels in
the first quarter of 2007 were consistent with the levels
originally expected for the quarter and have increased as
compared to the same period in 2006. Below is a further analysis
of our production by region for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(MMcfe/d)
|
|
|
United States
|
|
|
|
|
|
|
|
|
Onshore
|
|
|
363
|
|
|
|
334
|
|
Texas Gulf Coast
|
|
|
189
|
|
|
|
195
|
|
Gulf of Mexico Shelf/south
Louisiana
|
|
|
182
|
|
|
|
133
|
|
International
|
|
|
|
|
|
|
|
|
Brazil
|
|
|
16
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated
|
|
|
750
|
|
|
|
694
|
|
|
|
|
|
|
|
|
|
|
Four
Star(1)
|
|
|
70
|
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts represent our proportionate
share of the production of Four Star.
|
In our Onshore region, our 2007 production increased through
capital projects where we maintained or increased production in
most of our major operating areas, with the majority of growth
coming from the Rockies. In the Texas Gulf Coast region, our
2007 production volumes remained stable as the acquisition of
properties in the first quarter of 2007 mostly offset natural
production declines and the sale of certain non-strategic south
Texas properties in 2006. In the Gulf of Mexico Shelf/south
Louisiana region, we increased production in 2007 through
development projects in the West Cameron area and our Catapult
project and recovery of volumes shut-in by hurricane damage,
which helped to offset natural production declines. In Brazil,
production volumes decreased primarily due to a contractual
reduction of our ownership interest in the Pescada-Arabaiana
fields in early 2006.
26
Drilling
Onshore. We realized a 100 percent
success rate on 152 gross wells drilled.
Texas Gulf Coast. We experienced a
91 percent success rate on 23 gross wells drilled.
Gulf of Mexico Shelf and south Louisiana. We
drilled two unsuccessful wells in the first quarter of 2007, but
expect to place four to eight wells in production for the
remainder of 2007.
Brazil. In the Pinauna Field in the Camamu
Basin, we began drilling two exploratory wells. Additionally, we
began drilling an exploration well with Petrobras in the ES-5
Block in the Espirito Santo Basin. These three exploratory wells
are expected to reach their targeted zones and be evaluated by
the third quarter of 2007.
Egypt. In April 2007, we received formal
government approval and signed the concession agreement for the
South Mariut Block. We paid $3 million for the concession
and agreed to a $22 million firm working commitment over
three years. The block is approximately 1.2 million acres
and is located onshore in the western part of the Nile Delta.
Cash Operating Costs. We monitor the cash
operating costs required to produce our natural gas and oil
volumes. These costs are generally reported on a per Mcfe basis
and include total operating expenses less depreciation,
depletion and amortization expense and cost of products and
services on our income statement. During the three months ended
March 31, 2007, cash operating costs increased to
$1.99/Mcfe as compared to $1.71/Mcfe for the same period in
2006, primarily as a result of higher production costs from
higher workover activity levels, industry inflation in services,
labor and material costs and lower severance tax credits.
Capital Expenditures. Our total natural gas
and oil capital expenditures on an accrual basis were
$606 million for the quarter ended March 31, 2007,
including $254 million to acquire producing properties and
undeveloped acreage in Zapata County, Texas in January 2007. The
acquisition in Zapata County complements our existing Texas Gulf
Coast operations and provides a re-entry into the Lobo area.
Outlook
For the full year 2007, we anticipate the following on a
worldwide basis:
|
|
|
|
|
Average daily production volumes of approximately
740 MMcfe/d to 795 MMcfe/d, which excludes
approximately 60 MMcfe/d to 65 MMcfe/d from our equity
investment in Four Star.
|
|
|
|
Capital expenditures, excluding acquisitions, between
$1.4 billion and $1.5 billion. While 85% of the
planned 2007 capital program is allocated to our domestic
program, we plan to invest approximately $215 million
internationally during 2007, primarily in our Brazil exploration
and development program.
|
|
|
|
Average cash operating costs which include production costs,
general and administrative expenses and taxes (other than
production and income) of approximately $1.68/Mcfe to
$2.00/Mcfe; and
|
|
|
|
Depreciation, depletion, and amortization rate between
$2.50/Mcfe and $2.75/Mcfe.
|
27
Price
Risk Management Activities
As part of our strategy, we enter into derivative contracts on
our natural gas and oil production to stabilize cash flows, to
reduce the risk and financial impact of downward commodity price
movements on commodity sales and to protect the economic
assumptions associated with our capital investment programs.
Because this strategy only partially reduces our exposure to
downward movements in commodity prices, our reported results of
operations, financial position and cash flows can be impacted
significantly by movements in commodity prices from period to
period. Adjustments to our hedging strategy and the decision to
enter into new positions or to alter existing positions are made
based on the goals of the overall company.
In March 2007, we entered into additional floor and ceiling
option contracts on approximately 44 TBtu of our anticipated
2008 natural gas production. The following table reflects the
contracted volumes and the minimum, maximum and average prices
we will receive under our derivative contracts when combined
with the sale of the underlying hedged production as of
March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price
|
|
|
|
|
|
|
|
|
Basis
|
|
|
|
Swaps(1)
|
|
|
Floors(1)
|
|
|
Ceilings(1)
|
|
|
Swaps(1)(2)
|
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
59
|
|
|
$
|
7.71
|
|
|
|
41
|
|
|
$
|
8.00
|
|
|
|
41
|
|
|
$
|
16.89
|
|
|
|
83
|
|
2008
|
|
|
5
|
|
|
$
|
3.42
|
|
|
|
44
|
|
|
$
|
8.00
|
|
|
|
44
|
|
|
$
|
10.53
|
|
|
|
|
|
2009
|
|
|
5
|
|
|
$
|
3.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010-2012
|
|
|
11
|
|
|
$
|
3.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
144
|
|
|
$
|
35.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
lock-in locational price differences on a portion of
our natural gas production in Texas and Oklahoma.
|
Our natural gas fixed price swaps, floors and ceiling contracts
in the table above are designated as accounting hedges. Gains
and losses associated with these natural gas contracts are
deferred in accumulated other comprehensive income and will be
recognized in earnings upon the sale of the related production
at market prices, resulting in a realized price that is
approximately equal to the hedged price. Our oil fixed price
swaps and approximately 39 TBtu of our natural gas basis swaps
are not designated as accounting hedges. Accordingly, changes in
the fair value of these swaps are not deferred, but are
recognized in earnings each period.
The table above does not include (i) net realized gains on
derivative contracts we previously accounted for as hedges on
which we will record an additional $45 million as natural
gas and oil revenues for the remainder of 2007, which are also
currently deferred in accumulated other comprehensive income or
(ii) contracts entered into by our Marketing segment as
further described in that segment. For the consolidated impact
of the entirety of El Pasos production-related price
risk management activities on our liquidity, see the discussion
of factors that could impact our liquidity in Liquidity and
Capital Resources.
28
Financial
Results and Variance Analysis
The tables below and the discussion that follows provide our
financial results and analysis of significant variances in these
results during the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
408
|
|
|
$
|
366
|
|
Oil, condensate and NGL
|
|
|
88
|
|
|
|
90
|
|
Other
|
|
|
9
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
505
|
|
|
|
466
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
|
(170
|
)
|
|
|
(146
|
)
|
Production
costs(1)
|
|
|
(86
|
)
|
|
|
(64
|
)
|
Cost of products and services
|
|
|
(24
|
)
|
|
|
(22
|
)
|
General and administrative expenses
|
|
|
(46
|
)
|
|
|
(42
|
)
|
Taxes, other than production and
income
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
(328
|
)
|
|
|
(275
|
)
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
177
|
|
|
|
191
|
|
Other
income(2)
|
|
|
2
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
EBIT
|
|
$
|
179
|
|
|
$
|
199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Production costs include lease
operating costs and production related taxes (including ad
valorem and severance taxes).
|
|
(2) |
|
Includes equity earnings from our
investment in Four Star.
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Consolidated volumes, prices
and costs per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMcf)
|
|
|
56,713
|
|
|
|
52,029
|
|
|
|
9
|
%
|
Prices ($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices including
hedges
|
|
$
|
7.19
|
|
|
$
|
7.03
|
|
|
|
2
|
%
|
Average realized prices excluding
hedges
|
|
$
|
6.46
|
|
|
$
|
7.77
|
|
|
|
(17
|
)%
|
Average transportation costs
($/Mcf)
|
|
$
|
0.31
|
|
|
$
|
0.24
|
|
|
|
29
|
%
|
Oil, condensate and NGL
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MBbls)
|
|
|
1,788
|
|
|
|
1,745
|
|
|
|
2
|
%
|
Prices ($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized prices including
hedges
|
|
$
|
49.32
|
|
|
$
|
51.25
|
|
|
|
(4
|
)%
|
Average realized prices excluding
hedges
|
|
$
|
50.07
|
|
|
$
|
52.60
|
|
|
|
(5
|
)%
|
Average transportation costs
($/Bbl)
|
|
$
|
0.76
|
|
|
$
|
1.25
|
|
|
|
(39
|
)%
|
Total equivalent volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
MMcfe
|
|
|
67,442
|
|
|
|
62,500
|
|
|
|
8
|
%
|
MMcfe/d
|
|
|
750
|
|
|
|
694
|
|
|
|
8
|
%
|
Production costs and other cash
operating costs ($/Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average lease operating costs
|
|
$
|
0.95
|
|
|
$
|
0.73
|
|
|
|
30
|
%
|
Average production taxes
|
|
|
0.32
|
|
|
|
0.29
|
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production
costs(1)
|
|
|
1.27
|
|
|
|
1.02
|
|
|
|
25
|
%
|
Average general and administrative
expenses
|
|
|
0.69
|
|
|
|
0.67
|
|
|
|
3
|
%
|
Average taxes, other than
production and income
|
|
|
0.03
|
|
|
|
0.02
|
|
|
|
50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash operating costs
|
|
$
|
1.99
|
|
|
$
|
1.71
|
|
|
|
16
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit of production depletion cost
($/Mcfe)
|
|
$
|
2.40
|
|
|
$
|
2.20
|
|
|
|
9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unconsolidated affiliate
volumes (Four Star)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
4,941
|
|
|
|
4,507
|
|
|
|
|
|
Oil, condensate and NGL (MBbls)
|
|
|
233
|
|
|
|
309
|
|
|
|
|
|
Total equivalent volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
MMcfe
|
|
|
6,338
|
|
|
|
6,360
|
|
|
|
|
|
MMcfe/d
|
|
|
70
|
|
|
|
71
|
|
|
|
|
|
|
|
|
(1) |
|
Production costs include lease
operating costs and production related taxes (including ad
valorem and severance taxes).
|
30
Quarter
Ended March 31, 2007 Compared to Quarter Ended
March 31, 2006
The table below outlines the variances in our operating results
for the quarter ended March 31, 2007 as compared to the
same period in 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variances
|
|
|
|
Operating
|
|
|
Operating
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
Expenses
|
|
|
Other
|
|
|
EBIT
|
|
|
|
Favorable/(Unfavorable)
|
|
|
|
(In millions)
|
|
|
Natural Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lower realized prices in 2007
|
|
$
|
(74
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(74
|
)
|
Impact of hedges
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
80
|
|
Higher production volumes in 2007
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
Oil, Condensate and NGL
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lower realized prices in 2007
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
Impact of hedges
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Higher production volumes in 2007
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of
derivatives not designated as accounting hedges
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Other
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
Depreciation, Depletion and
Amortization Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Higher depletion rate in 2007
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
(13
|
)
|
Higher production volumes in 2007
|
|
|
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
(11
|
)
|
Production Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Higher lease operating costs in
2007
|
|
|
|
|
|
|
(18
|
)
|
|
|
|
|
|
|
(18
|
)
|
Higher production taxes in 2007
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
(4
|
)
|
General and Administrative
Expenses
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
(4
|
)
|
Other
|
|
|
|
|
|
|
(3
|
)
|
|
|
(6
|
)
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Variances
|
|
$
|
39
|
|
|
$
|
(53
|
)
|
|
$
|
(6
|
)
|
|
$
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues. In 2007, our revenues
increased as compared to 2006 primarily due to the success in
our drilling program which resulted in higher production volumes
as previously discussed. Offsetting the positive impact of
higher production volumes were reduced prices as compared to
2006. However, the effect of our hedging program somewhat
mitigated the impact of price declines as gains on hedging
settlements were $40 million during the first quarter of
2007 as compared to losses of $41 million in the first
quarter of 2006.
Depreciation, depletion and amortization
expense. During the first quarter of 2007, our
depletion rate increased as compared to the same period in 2006
as a result of higher finding and development costs due to
service cost inflation, mechanical problems in executing our
drilling program during 2006 and downward revisions in previous
estimates of reserves due to lower commodity prices.
Production costs. In the first quarter of
2007, our lease operating costs increased as compared to the
same period in 2006 due to higher workover activity levels,
industry inflation in services, labor and material costs and
lower severance tax credits.
General and administrative expenses. Our
general and administrative expenses increased during 2007 as
compared to the same period in 2006, primarily due to higher
labor costs.
Other. During the first quarter of 2007, Four
Stars equity earnings decreased by $8 million as
compared to the same period in 2006 due to lower natural gas
prices, higher production costs and higher depreciation,
depletion, and amortization expense.
31
Marketing
Segment
Overview. Our Marketing segment markets our
Exploration and Production segments natural gas and oil
production and manages the companys overall price risks,
primarily through the use of natural gas and oil derivative
contracts. This segment also continues to manage and liquidate
our remaining historical natural gas supply, transportation,
power and other natural gas contracts entered into prior to the
deterioration of the energy trading environment in 2002. To the
extent it is economical to do so, we may liquidate certain of
these remaining historical contracts before their expiration,
which could affect our operating results in future periods . For
a further discussion of our contracts in this segment including
our expected earnings volatility by contract type, see our 2006
Annual Report on
Form 10-K.
Operating Results. During the quarter ended
March 31, 2007, we generated an EBIT loss of
$135 million primarily driven by
mark-to-market
changes in the fair value of our options and swaps intended to
manage the price risk of the companys natural gas and oil
production. We also incurred losses resulting from our remaining
positions in our historical natural gas and power books and from
terminating a gas supply contract as part of the continued
efforts to reduce our exposure to these contracts. Below is
further information about our overall operating results during
each of the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Gross Margin by Significant
Contract Type:
|
|
|
|
|
|
|
|
|
Production-Related Natural Gas
and Oil Derivative
Contracts
|
|
|
|
|
|
|
|
|
Changes in fair value of
derivatives
|
|
$
|
(87
|
)
|
|
$
|
162
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
(87
|
)
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
Contracts Related to Historical
Trading Operations:
|
|
|
|
|
|
|
|
|
Natural gas transportation-related
natural gas contracts:
|
|
|
|
|
|
|
|
|
Demand charges
|
|
|
(27
|
)
|
|
|
(35
|
)
|
Settlements
|
|
|
20
|
|
|
|
20
|
|
Changes in fair value of other
natural gas derivative contracts
|
|
|
(24
|
)
|
|
|
47
|
|
Changes in fair value of power
contracts
|
|
|
(17
|
)
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
Gross
margin(1)
|
|
|
(48
|
)
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
Total gross margin
|
|
|
(135
|
)
|
|
|
205
|
|
Operating expenses
|
|
|
(1
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(136
|
)
|
|
|
200
|
|
Other income, net
|
|
|
1
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
EBIT
|
|
$
|
(135
|
)
|
|
$
|
208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross margin consists of revenues
from commodity marketing activities less costs of commodities
sold, including changes in the fair value of derivative
contracts.
|
Production-related
Natural Gas and Oil Derivative Contracts
Options and swaps. Our production-related
natural gas and oil derivative contracts are designed to provide
protection to El Paso against changes in natural gas and
oil prices. These are in addition to those contracts entered
into by our Exploration and Production segment which are further
discussed in that segment. For the consolidated impact of all of
El Pasos production-related price risk management
activities, refer to our Liquidity and Capital Resources
discussion. Our production-related derivatives consist of
various option contracts which are
32
marked-to-market
in our results each period based on changes in commodity prices.
Listed below are the volumes and average prices associated with
our production-related derivative contracts as of March 31,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floors(1)
|
|
|
Ceilings(1)
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Price
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
67
|
|
|
$
|
7.50
|
|
|
|
|
|
|
$
|
|
|
2008
|
|
|
18
|
|
|
$
|
6.00
|
|
|
|
18
|
|
|
$
|
10.00
|
|
2009
|
|
|
17
|
|
|
$
|
6.00
|
|
|
|
17
|
|
|
$
|
8.75
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
744
|
|
|
$
|
55.00
|
|
|
|
744
|
|
|
$
|
59.86
|
|
2008
|
|
|
930
|
|
|
$
|
55.00
|
|
|
|
930
|
|
|
$
|
57.03
|
|
|
|
|
(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.
|
We experience volatility in our financial results based on
changes in the fair value of our option contracts which
generally move in the opposite direction from changes in
commodity prices. During the quarter ended March 31, 2007,
increases in commodity prices reduced the fair value of our
option contracts resulting in a loss on these contracts, while
in the quarter ended March 31, 2006, decreases in commodity
prices increased the fair value of our option contracts
resulting in a gain on these contracts. However, during the
quarter ended March 31, 2007, we received cash of
approximately $17 million on contracts that settled during
the period, while in the quarter ended March 31, 2006, we
paid approximately $13 million for contracts that settled
during the period.
Contracts
Related to Historical Trading Operations
Natural gas transportation-related
contracts. As of March 31, 2007, our
transportation contracts provide us with approximately
0.8 Bcf/d of pipeline capacity that require us to pay
approximately $83 million in demand charges for the
remainder of 2007. Effective November 1, 2007, our Alliance
capacity will transfer to a third party and our demand charges
will be reduced to an average of $46 million annually from
2008 to 2011. The recovery of demand charges and profitability
of our transportation contracts is dependent upon our ability to
use or remarket the contracted pipeline capacity, which is
impacted by a number of factors as described in our 2006 Annual
Report on
Form 10-K.
These transportation contracts are accounted for on an accrual
basis and impact our gross margin as delivery or service under
the contracts occurs. The following table is a summary of our
demand charges (in millions) and our percentage of recovery of
these charges for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Alliance:
|
|
|
|
|
|
|
|
|
Demand charges
|
|
$
|
16
|
|
|
$
|
16
|
|
Recovery
|
|
|
48
|
%
|
|
|
19
|
%
|
Other:
|
|
|
|
|
|
|
|
|
Demand charges
|
|
$
|
11
|
|
|
$
|
19
|
|
Recovery
|
|
|
100
|
%
|
|
|
87
|
%
|
Other natural gas derivative contracts. In
addition to our transportation-related natural gas contracts, we
have other contracts with third parties that require us to
purchase or deliver natural gas primarily at market prices.
During 2006, we divested or entered into transactions to divest
of a substantial portion of these natural gas contracts, which
substantially reduced our future cash and earnings exposure to
price movements on these contracts. During the quarter ended
March 31, 2007, we assigned a weather call derivative which
had required us to supply gas in the northeast region if
temperatures fell to specific levels resulting in a charge of
$13 million. During the quarter ended March 31, 2006,
we recognized a $49 million gain associated with the
assignment of certain natural gas derivative contracts to supply
natural gas in the southeastern U.S.
Power Contracts. Our first quarter 2007 losses
and first quarter 2006 gains on our power contracts relate to
four contracts that require us to swap locational differences in
power prices between several power plants in the
33
Pennsylvania-New Jersey-Maryland (PJM) eastern region with the
PJM west hub, and provide installed capacity in the PJM power
pool. During 2005 and 2006, we entered into contracts that
eliminated the commodity risk associated with these contracts. A
dispute has arisen with a downstream purchaser with regard to
the region within PJM that capacity must be made available under
one of our remaining power contracts. Although we believe that
we are entitled to make such capacity available at any delivery
point within the PJM power pool, if we are restricted to
delivering such capacity in particular regions, the fair value
of that power contract and our operating results could be
negatively impacted.
Power
Segment
Our Power segment consists of assets in Brazil, Asia and Central
America. We continue to pursue the sales of these remaining
power investments. As of March 31, 2007, our remaining
investment, guarantees and letters of credit related to power
projects in this segment totaled approximately $662 million
which consisted of approximately $624 million in equity
investments and notes receivable and approximately
$38 million in financial guarantees and letters of credit,
as follows (in millions):
|
|
|
|
|
Area
|
|
Amount
|
|
|
Brazil
|
|
|
|
|
Porto Velho
|
|
$
|
329
|
|
Manaus & Rio Negro
|
|
|
95
|
|
Pipeline projects
|
|
|
145
|
|
Asia & Central
America
|
|
|
93
|
|
|
|
|
|
|
Total investment, guarantees and
letters of credit
|
|
$
|
662
|
|
|
|
|
|
|
Brazil. We continue to evaluate the potential
opportunity to sell our interest in our Porto Velho project to
the power purchaser who has expressed an interest in acquiring
our interest in the plant. Additionally, we are continuing to
monitor other matters that could impact our other Brazilian
investments as further described in Item 8, Financial
Statements and Supplementary Data, Note 18 of our 2006
Annual Report on
Form 10-K.
Asia and Central America. We continue to
pursue the sale of our four remaining investments in Asia and
Central America. Until the sale of these investments is
completed, any changes in regional political and economic
conditions could negatively impact the anticipated proceeds,
which could result in additional impairments of our investments.
Operating Results. During the quarters ended
March 31, 2007 and 2006, our Power segment generated EBIT
of $18 million and $3 million, primarily from our
Porto Velho project in Brazil which generated EBIT of
$13 million and $7 million. In 2006, our operating
results were also impacted by operations and impairments of
certain domestic and other international operations
substantially all of which have been sold. During both periods,
we did not recognize earnings from certain of our Asian and
Central American assets based on our inability to realize
earnings through the expected selling price of these assets.
34
Corporate
and Other Expenses, Net
Our corporate activities include our general and administrative
functions as well as a number of miscellaneous businesses, which
do not qualify as operating segments and are not material to our
current period results. The following is a summary of
significant items impacting the EBIT in our corporate operations
for the quarters ended March 31:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Loss on extinguishment of debt
|
|
$
|
(201
|
)
|
|
$
|
(6
|
)
|
Foreign currency fluctuations on
Euro-denominated debt
|
|
|
(2
|
)
|
|
|
(4
|
)
|
Change in litigation, insurance
and other reserves
|
|
|
(28
|
)
|
|
|
(22
|
)
|
Other, primarily interest income
|
|
|
21
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
Total EBIT
|
|
$
|
(210
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Extinguishment of debt. During the first
quarter of 2007, in conjunction with the repurchase of
approximately $3.5 billion of our debt obligations, we
recorded a $201 million charge in our income statement for
the loss on extinguishment of these obligations. For further
information on our debt, see Item 1, Financial Statements,
Note 6.
Litigation, Insurance, and Other Reserves. We
have a number of pending litigation matters and reserves related
to our historical business operations. Adverse rulings or
unfavorable outcomes or settlements against us related to these
matters have impacted and may further impact our future results.
Interest
and Debt Expense
Interest and debt expense for the quarter ended March 31,
2007 decreased to $283 million compared to
$331 million for the same period in 2006 due primarily to
the retirement (net of issuances) of approximately
$2.6 billion of debt during 2006. In the first quarter of
2007, we further reduced our debt obligations, net of issuances
by an additional $3 billion which should significantly
decrease our interest expense in future periods.
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Income taxes from continuing
operations
|
|
$
|
(19
|
)
|
|
$
|
124
|
|
Effective tax rate
|
|
|
28
|
%
|
|
|
29
|
%
|
For a discussion of our effective tax rates and other matters
impacting our income taxes, see Item 1, Financial
Statements, Note 3.
Discontinued
Operations
Income from our discontinued operations for the quarters ended
March 31, 2007 and 2006, was $677 million and
$55 million. In February 2007, we sold ANR, and related
operations and recognized a gain in the first quarter
of approximately $651 million, net of taxes of
$356 million.
Commitments
and Contingencies
For a further discussion of our commitments and contingencies,
see Item I, Financial Statements, Note 7 which is
incorporated herein by reference.
35
Liquidity
and Capital Resources
Sources and Uses of Cash. Our primary sources
of cash are cash flow from operations and amounts available to
us under revolving credit facilities. In 2007, our sources also
include proceeds from asset sales. On occasion and as conditions
warrant, we also generate funds through capital market
activities. Our primary uses of cash are funding the capital
expenditure programs of our pipeline and exploration and
production operations, meeting operating needs, and repaying
debt when due or repurchasing certain debt obligations when
conditions warrant.
Overview of Cash Flow Activities. For the
quarters ended March 31, 2007 and 2006, our cash flows of
continuing operations are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In billions)
|
|
|
Cash Flow from
Operations
|
|
|
|
|
|
|
|
|
Continuing operating
activities
|
|
|
|
|
|
|
|
|
Net income before discontinued
operations
|
|
$
|
|
|
|
$
|
0.3
|
|
Loss on debt extinguishment
|
|
|
0.2
|
|
|
|
|
|
Other income adjustments
|
|
|
0.3
|
|
|
|
0.4
|
|
Change in other assets and
liabilities
|
|
|
(0.1
|
)
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
Total cash flow from operations
|
|
$
|
0.4
|
|
|
$
|
0.9
|
|
|
|
|
|
|
|
|
|
|
Other Cash Inflows
|
|
|
|
|
|
|
|
|
Continuing investing
activities
|
|
|
|
|
|
|
|
|
Net proceeds from the sale of
assets and investments
|
|
$
|
|
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
Continuing financing
activities
|
|
|
|
|
|
|
|
|
Net proceeds from the issuance of
long-term debt
|
|
|
1.4
|
|
|
|
|
|
Contribution from discontinued
operations
|
|
|
3.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other cash inflows
|
|
$
|
4.8
|
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
Cash Outflows
|
|
|
|
|
|
|
|
|
Continuing investing
activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
0.8
|
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.8
|
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
Continuing financing
activities
|
|
|
|
|
|
|
|
|
Payments to retire long-term debt
and other financing obligations
|
|
|
4.7
|
|
|
|
0.9
|
|
Dividends and other
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.7
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
Total cash outflows
|
|
$
|
5.5
|
|
|
$
|
1.4
|
|
|
|
|
|
|
|
|
|
|
Net change in cash
|
|
$
|
(0.3
|
)
|
|
$
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
36
During the first quarter of 2007, we generated positive
operating cash flow of approximately $0.4 billion,
primarily as a result of cash provided by our pipeline and
exploration and production operations less interest paid during
the quarter on our debt obligations which includes interest
prepaid due to early extinguishment of debt. We utilized this
operating cash flow generated and cash from our discontinued
operations to fund both maintenance and growth projects in our
pipeline and exploration and production operations and reduce
our debt obligations (see Item 1, Financial Statements,
Note 6). Cash generated from our discontinued operations
reflected above consists of the following for the quarter ended
March 31, 2007:
|
|
|
|
|
|
|
(In billions)
|
|
|
Operating cash flow from
discontinued operations
|
|
$
|
|
|
Proceeds from sale of ANR and
related assets
|
|
|
3.7
|
|
Payments to retire ANR debt
obligations
|
|
|
(0.3
|
)
|
|
|
|
|
|
Contribution from discontinued
operations
|
|
$
|
3.4
|
|
|
|
|
|
|
Our capital expenditures, including acquisitions for the quarter
and the amount we expect to spend for the remainder of 2007 to
grow and maintain our businesses are as follows (in billions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
|
|
|
|
|
|
|
March 31, 2007
|
|
|
2007 Remaining
|
|
|
Total
|
|
|
Maintenance
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines
|
|
$
|
0.1
|
|
|
$
|
0.3
|
|
|
$
|
0.4
|
|
Exploration and Production
|
|
|
0.4
|
|
|
|
0.8
|
|
|
|
1.2
|
|
Growth
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipelines
|
|
|
0.1
|
|
|
|
0.5
|
|
|
|
0.6
|
|
Exploration and Production
|
|
|
0.2
|
|
|
|
0.3
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.8
|
|
|
$
|
1.9
|
|
|
$
|
2.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The substantial repayment of debt obligations during the first
quarter of 2007 was a milestone in improving our credit profile
and credit ratings. In March 2007, Moodys Investor
Services upgraded our pipeline subsidiaries senior
unsecured debt rating to an investment grade rating of Baa3 and
upgraded El Pasos senior unsecured debt rating to Ba3
while maintaining a positive outlook. Additionally, in March
2007, (i) Standard and Poors upgraded our pipeline
subsidiaries senior unsecured debt rating to BB and
upgraded El Pasos senior unsecured debt rating to BB-
maintaining a positive outlook and (ii) Fitch Ratings
initiated coverage on El Paso assigning a rating of BB+ on
our senior unsecured debt and an investment grade rating of BBB-
to our pipeline subsidiaries senior unsecured debt.
Additionally, the refinancing in March and April of 2007 of
approximately $750 million of the debt of SNG and EPNG, our
subsidiaries, will further improve our credit profile by
providing us with a lower cost of borrowing and less restrictive
covenants on this debt.
Liquidity/Cash Flow Outlook. For the remainder
of 2007, we expect to continue to generate positive operating
cash flows. We anticipate using these amounts together with
amounts borrowed under credit facilities, proceeds from
remaining asset sales, and proceeds from capital market
activities, if necessary, for working capital requirements,
expected capital expenditures and to repay debt as it matures.
We have approximately $0.3 billion of debt that matures
through March 31, 2008, and approximately $0.1 billion
of debt that the holders can require us to redeem prior to its
scheduled maturity in the second quarter of 2007.
Factors That Could Impact Our Future
Liquidity. Based on the simplification of our
capital structure and our businesses, we have reduced the amount
of liquidity needed in the normal course of business. However,
our liquidity needs could increase or decrease based on certain
factors described below. For a complete discussion of risk
factors that could impact our liquidity, see our 2006 Annual
Report on
Form 10-K.
37
Price Risk Management Activities and Cash Margining
Requirements. Our Exploration and Production and
Marketing segments have derivative contracts to provide price
protection on a portion of our anticipated natural gas and oil
production. As of March 31, 2007, these contracts include
new floor and ceiling contracts entered into in the first
quarter of 2007 on approximately 44 TBtu of our anticipated 2008
natural gas production. The following table shows the contracted
volumes and the minimum, maximum and average cash prices that we
will receive under our derivative contracts when combined with
the sale of the underlying production as of March 31, 2007.
These cash prices may differ from the income impacts of our
derivative contracts, depending on whether the contracts are
designated as hedges for accounting purposes or not. The
individual segment discussions provide additional information on
the income impacts of our derivative contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis
|
|
|
|
Swaps(1)
|
|
|
Floors(1)
|
|
|
Ceilings(1)
|
|
|
Swaps(1)(2)
|
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
59
|
|
|
$
|
7.71
|
|
|
|
108
|
|
|
$
|
7.69
|
|
|
|
41
|
|
|
$
|
16.89
|
|
|
|
83
|
|
2008
|
|
|
5
|
|
|
$
|
3.42
|
|
|
|
62
|
|
|
$
|
7.42
|
|
|
|
62
|
|
|
$
|
10.38
|
|
|
|
|
|
2009
|
|
|
5
|
|
|
$
|
3.56
|
|
|
|
17
|
|
|
$
|
6.00
|
|
|
|
17
|
|
|
$
|
8.75
|
|
|
|
|
|
2010-2012
|
|
|
11
|
|
|
$
|
3.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
144
|
|
|
$
|
35.15
|
|
|
|
744
|
|
|
$
|
55.00
|
|
|
|
744
|
|
|
$
|
59.86
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
930
|
|
|
$
|
55.00
|
|
|
|
930
|
|
|
$
|
57.03
|
|
|
|
|
|
|
|
|
(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
lock-in locational price differences on a portion of
our natural gas production in Texas and Oklahoma.
|
We currently post letters of credit for a substantial portion of
the required margin on natural gas fixed price swap contracts
that are at prices below current market prices. Historically we
were required to post cash margin deposits for these amounts.
During the first quarter of 2007, approximately $20 million
of posted cash margin deposits were returned to us resulting
from settlement of the related contracts. For the remainder of
2007, based on current prices, we expect approximately
$0.2 billion of the total of $1.1 billion in
collateral outstanding at March 31, 2007 to be returned to
us in the form of both cash margin deposits and letters of
credit.
Depending on changes in commodity prices, we could be required
to post additional margin or recover margin earlier than
anticipated. Based on our derivative positions at March 31,
2007, a
$0.10/MMBtu
increase in the price of natural gas would result in an increase
in our margin requirements of approximately $11 million
which consists of $3 million for transactions that settle
in the remainder of 2007, $5 million for transactions that
settle in 2008 and $3 million for transactions that settle
in 2009 and thereafter. We have a $250 million unsecured
contingent letter of credit facility available to us if the
average NYMEX gas price strip for the remaining calendar months
through March 2008 reaches $11.75 per MMBtu, which is
further described in Item I, Financial Statements,
Note 6.
Hurricanes. We continue to repair damages to
our pipeline and other facilities caused by Hurricanes Katrina
and Rita in 2005. In 2007 and 2008, we expect remaining repair
costs of approximately $125 million (a substantial portion
of which is capital related) and insurance reimbursements of
approximately $195 million for cumulative recoverable costs
from our insurers. While our capital expenditures and liquidity
may vary from period to period, we do not believe our remaining
hurricane related expenditures will materially impact our
overall liquidity or financial results.
38
Commodity-Based
Derivative Contracts
We use derivative financial instruments in our Exploration and
Production and Marketing segments to manage the price risk of
commodities. In the tables below, derivatives designated as
accounting hedges primarily consist of collars and swaps used to
hedge natural gas production. Other commodity-based derivative
contracts relate to derivative contracts not designated as
accounting hedges, such as options, swaps and other natural gas
and power purchase and supply contracts. The following table
details the fair value of our commodity-based derivative
contracts by year of maturity and valuation methodology as of
March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity
|
|
|
Maturity
|
|
|
Maturity
|
|
|
Maturity
|
|
|
Maturity
|
|
|
Total
|
|
|
|
Less Than
|
|
|
1 to 3
|
|
|
4 to 5
|
|
|
6 to 10
|
|
|
Beyond
|
|
|
Fair
|
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
Years
|
|
|
10 Years
|
|
|
Value
|
|
|
|
(In millions)
|
|
|
Derivatives designated as
accounting hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
19
|
|
|
$
|
14
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
33
|
|
Liabilities
|
|
|
(47
|
)
|
|
|
(40
|
)
|
|
|
(29
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
(119
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as
accounting hedges
|
|
|
(28
|
)
|
|
|
(26
|
)
|
|
|
(29
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
(86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other commodity-based derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
positions(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
(6
|
)
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26
|
)
|
Non-exchange traded positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
77
|
|
|
|
65
|
|
|
|
47
|
|
|
|
37
|
|
|
|
9
|
|
|
|
235
|
|
Liabilities
|
|
|
(286
|
)
|
|
|
(387
|
)
|
|
|
(253
|
)
|
|
|
(209
|
)
|
|
|
(6
|
)
|
|
|
(1,141
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other commodity-based
derivatives
|
|
|
(215
|
)
|
|
|
(342
|
)
|
|
|
(206
|
)
|
|
|
(172
|
)
|
|
|
3
|
|
|
|
(932
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commodity-based derivatives
|
|
$
|
(243
|
)
|
|
$
|
(368
|
)
|
|
$
|
(235
|
)
|
|
$
|
(175
|
)
|
|
$
|
3
|
|
|
$
|
(1,018
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These positions are traded on
active exchanges such as the New York Mercantile Exchange, the
International Petroleum Exchange and the London Clearinghouse.
|
The following is a reconciliation of our commodity-based
derivatives for the quarter ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
|
Other
|
|
|
Total
|
|
|
|
Designated as
|
|
|
Commodity-
|
|
|
Commodity-
|
|
|
|
Accounting
|
|
|
Based
|
|
|
Based
|
|
|
|
Hedges
|
|
|
Derivatives
|
|
|
Derivatives
|
|
|
|
(In millions)
|
|
|
Fair value of contracts
outstanding at January 1, 2007
|
|
$
|
61
|
|
|
$
|
(456
|
)
|
|
$
|
(395
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contract settlements
during the
period(1)
|
|
|
(29
|
)
|
|
|
(375
|
)
|
|
|
(404
|
)
|
Change in fair value of contracts
|
|
|
(129
|
)
|
|
|
(126
|
)
|
|
|
(255
|
)
|
Assignment of contracts
|
|
|
|
|
|
|
25
|
|
|
|
25
|
|
Option premiums
paid(2)
|
|
|
11
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in contracts
outstanding during the period
|
|
|
(147
|
)
|
|
|
(476
|
)
|
|
|
(623
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts
outstanding at March 31, 2007
|
|
$
|
(86
|
)
|
|
$
|
(932
|
)
|
|
$
|
(1,018
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the first quarter of 2007,
we settled contracts associated with approximately
$381 million of our assets from price risk management
activities by applying the related cash margin we held against
amounts due under those contracts.
|
|
(2) |
|
Amounts are net of premiums
received.
|
39
|
|
Item 3.
|
Quantitative
And Qualitative Disclosures About Market Risk
|
This information updates, and you should read it in conjunction
with, information disclosed in our 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 are no material changes in our quantitative and
qualitative disclosures about market risks from those reported
in our Annual Report on
Form 10-K,
except as presented below:
Commodity
Price Risk
Production-Related Derivatives. We attempt to
mitigate commodity price risk and stabilize cash flows
associated with El Pasos forecasted sales of natural
gas and oil production through the use of derivative natural gas
and oil swaps, basis swaps and option contracts. These
derivative contracts are entered into by both our
Exploration & Production and Marketing segments. The
table below presents the hypothetical sensitivity to changes in
fair values arising from immediate selected potential changes in
the quoted market prices of the derivative commodity instruments
used to mitigate these market risks. We have designated certain
of these derivatives as accounting hedges. Contracts that are
designated as accounting hedges will impact our earnings when
the related hedged production sales occur, and, as a result, any
gain or loss on these hedging derivatives would be substantially
offset by a corresponding gain or loss on the sale of the
underlying hedged commodity, which is not included in the table.
Contracts that are not designated as accounting hedges will
impact our earnings as the fair value of these derivatives
changes. Our production-related derivatives do not mitigate all
of the commodity price risk related to our forecasted sales of
natural gas and oil production and, as a result, we are subject
to commodity price risks on our remaining forecasted natural gas
and oil production.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10 Percent Increase
|
|
|
10 Percent Decrease
|
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
(Decrease)
|
|
|
Fair Value
|
|
|
Increase
|
|
|
Impact of changes in commodity
prices on derivative commodity instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2007
|
|
$
|
(118
|
)
|
|
$
|
(250
|
)
|
|
$
|
(132
|
)
|
|
$
|
3
|
|
|
$
|
121
|
|
December 31, 2006
|
|
$
|
124
|
|
|
$
|
(9
|
)
|
|
$
|
(133
|
)
|
|
$
|
264
|
|
|
$
|
140
|
|
Other Commodity-Based Derivatives. We have
various other financial instruments that are not utilized to
mitigate the commodity price risk associated with our natural
gas and oil production in our Marketing segment. Many of these
contracts, which include forwards, swaps, options and futures,
are long-term historical contracts that we either intend to
assign to third parties or to manage until their expiration. We
measure risks from these contracts on a daily basis using a
Value-at-Risk
simulation. This simulation allows us to determine the maximum
expected
one-day
unfavorable impact on the fair values of those contracts due to
adverse market movements over a defined period of time within a
specified confidence level and allows us to monitor our risk in
comparison to established thresholds. We use what is known as
the historical simulation technique for measuring
Value-at-Risk.
This technique simulates potential outcomes in the value of our
portfolio based on market-based price changes. Our exposure to
changes in fundamental prices over the long-term can vary from
the exposure using the
one-day
assumption in our
Value-at-Risk
simulations. We supplement our
Value-at-Risk
simulations with additional fundamental and market-based price
analyses, including scenario analysis and stress testing to
determine our portfolios sensitivity to underlying risks.
These analyses and our
Value-at-Risk
simulations do not include commodity exposures related to our
production-related derivatives (described above), our Marketing
segments natural gas transportation related contracts that
are accounted for under the accrual basis of accounting, or our
Exploration and Production segments sales of natural gas
and oil production.
Our maximum expected
one-day
unfavorable impact on the fair values of our other
commodity-based derivatives as measured by
Value-at-Risk
based on a confidence level of 95 percent and a
one-day
holding period was $4 million and $6 million as of
March 31, 2007 and December 31, 2006. We may
experience changes in our
Value-at-Risk
in the future if commodity prices are volatile.
40
|
|
Item 4.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
As of March 31, 2007, we carried out an evaluation under
the supervision and with the participation of our management,
including our CEO and our CFO, as to the effectiveness, design
and operation of our disclosure controls and procedures, as
defined by the Securities Exchange Act of 1934, as amended. 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 (SEC) reports we
file or submit under the Exchange Act is accurate, complete and
timely. Our management, including our CEO and 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. Based on the results of this
evaluation, our CEO and CFO concluded that our disclosure
controls and procedures are effective at March 31, 2007.
Changes
in Internal Control over Financial Reporting
There were no changes in our internal control over financial
reporting that have materially affected or are reasonably likely
to materially affect our internal control over financial
reporting during the first quarter of 2007.
41
PART II
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
See Part I, Item 1, Financial Statements, Note 7,
which is incorporated herein by reference. Additional
information about our legal proceedings can be found, in
Part I, Item 3 of our 2006 Annual Report on
Form 10-K
filed with the SEC.
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;
|
|
|
|
managements plans; and
|
|
|
|
goals and objectives for future operations.
|
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
the 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
forward-looking statements are described in our 2006 Annual
Report on
Form 10-K.
There have been no material changes in our risk factors since
that report.
|
|
Item 2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
None.
|
|
Item 3.
|
Defaults
Upon Senior Securities
|
None.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None.
42
|
|
Item 5.
|
Other
Information
|
None.
The Exhibit Index is incorporated herein by reference and
lists the exhibits required to be filed by this report by
Item 601(b)(10)(iii) of
Regulation S-K.
43
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: May 7, 2007
D. Mark Leland
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: May 7, 2007
John R. Sult
Senior Vice President and Controller
(Principal Accounting Officer)
44
EL PASO
CORPORATION
EXHIBIT INDEX
Each exhibit identified below is a part of this Report. Exhibits
filed with this Report are designated by an *. All
exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
*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.
|
45