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,
2010
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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 1-10042
Atmos Energy
Corporation
(Exact name of registrant as
specified in its charter)
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Texas and Virginia
(State or other jurisdiction
of
incorporation or organization)
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75-1743247
(IRS employer
identification no.)
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Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal
executive offices)
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75240
(Zip
code)
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(972) 934-9227
(Registrants telephone
number, including area code)
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 has submitted
electronically and posted on its website, if any, every
Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files).* Yes
o
No
o
* The registrant has not yet been phased into the interactive
data requirements.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2
of the
Exchange Act. (Check one):
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Large
accelerated
filer
þ
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Accelerated
filer
o
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Non-accelerated
filer
o
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Smaller
reporting
company
o
|
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange Act) Yes
o
No
þ
Number of shares outstanding of each of the issuers
classes of common stock, as of April 30, 2010.
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Class
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Shares Outstanding
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No Par Value
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93,147,184
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TABLE OF CONTENTS
GLOSSARY
OF KEY TERMS
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AEC
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Atmos Energy Corporation
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AEH
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Atmos Energy Holdings, Inc.
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AEM
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Atmos Energy Marketing, LLC
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AOCI
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Accumulated other comprehensive income
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APS
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Atmos Pipeline and Storage, LLC
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Bcf
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Billion cubic feet
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FASB
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Financial Accounting Standards Board
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Fitch
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Fitch Ratings, Ltd.
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GRIP
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Gas Reliability Infrastructure Program
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GSRS
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Gas System Reliability Surcharge
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ISRS
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Infrastructure System Replacement Surcharge
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Mcf
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Thousand cubic feet
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MMcf
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Million cubic feet
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Moodys
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Moodys Investors Services, Inc.
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NYMEX
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New York Mercantile Exchange, Inc.
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PPA
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Pension Protection Act of 2006
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RRC
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Railroad Commission of Texas
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RRM
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Rate Review Mechanism
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S&P
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Standard & Poors Corporation
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SEC
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United States Securities and Exchange Commission
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WNA
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Weather Normalization Adjustment
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1
PART I.
FINANCIAL INFORMATION
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Item 1.
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Financial
Statements
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ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
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March 31,
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September 30,
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2010
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2009
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(Unaudited)
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(In thousands, except
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share data)
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ASSETS
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Property, plant and equipment
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$
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6,295,260
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$
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6,086,618
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Less accumulated depreciation and amortization
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1,704,785
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1,647,515
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Net property, plant and equipment
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4,590,475
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4,439,103
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Current assets
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Cash and cash equivalents
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231,153
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111,203
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Accounts receivable, net
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546,356
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232,806
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Gas stored underground
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208,589
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352,728
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Other current assets
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121,261
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132,203
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Total current assets
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1,107,359
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828,940
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Goodwill and intangible assets
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739,750
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740,064
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Deferred charges and other assets
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315,606
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335,659
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$
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6,753,190
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$
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6,343,766
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CAPITALIZATION AND LIABILITIES
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Shareholders equity
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Common stock, no par value (stated at $.005 per share);
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200,000,000 shares authorized; issued and outstanding:
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March 31, 2010 93,146,535 shares;
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September 30, 2009 92,551,709 shares
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$
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466
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$
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463
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Additional paid-in capital
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1,809,331
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1,791,129
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Retained earnings
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550,259
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405,353
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Accumulated other comprehensive loss
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(21,213
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)
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(20,184
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)
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Shareholders equity
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2,338,843
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2,176,761
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Long-term debt
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2,159,475
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2,169,400
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Total capitalization
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4,498,318
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4,346,161
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Current liabilities
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Accounts payable and accrued liabilities
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521,913
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207,421
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Other current liabilities
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432,469
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457,319
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Short-term debt
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72,550
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Current maturities of long-term debt
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10,131
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131
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Total current liabilities
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964,513
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737,421
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Deferred income taxes
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594,269
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570,940
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Regulatory cost of removal obligation
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317,203
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321,086
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Deferred credits and other liabilities
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378,887
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368,158
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$
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6,753,190
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$
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6,343,766
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|
|
|
|
|
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|
See accompanying notes to condensed consolidated financial
statements
2
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF
INCOME
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Three Months Ended
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March 31
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2010
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2009
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(Unaudited)
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(In thousands, except
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per share data)
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Operating revenues
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|
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|
|
|
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Natural gas distribution segment
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$
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1,365,988
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$
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1,230,420
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Regulated transmission and storage segment
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55,181
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59,234
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Natural gas marketing segment
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692,152
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708,658
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Pipeline, storage and other segment
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9,050
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|
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12,272
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Intersegment eliminations
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(182,105
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)
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(189,178
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)
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|
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1,940,266
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1,821,406
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Purchased gas cost
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|
|
|
|
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Natural gas distribution segment
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|
980,603
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|
|
|
863,340
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Regulated transmission and storage segment
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|
|
|
|
|
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Natural gas marketing segment
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|
685,672
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|
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685,114
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Pipeline, storage and other segment
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|
|
1,369
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|
|
|
1,656
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Intersegment eliminations
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|
(181,699
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)
|
|
|
(188,755
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)
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|
|
|
|
|
|
|
|
|
|
|
1,485,945
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|
|
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1,361,355
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|
|
|
|
|
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Gross profit
|
|
|
454,321
|
|
|
|
460,051
|
|
Operating expenses
|
|
|
|
|
|
|
|
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Operation and maintenance
|
|
|
117,088
|
|
|
|
121,740
|
|
Depreciation and amortization
|
|
|
53,080
|
|
|
|
53,450
|
|
Taxes, other than income
|
|
|
59,613
|
|
|
|
58,314
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
229,781
|
|
|
|
233,504
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
224,540
|
|
|
|
226,547
|
|
Miscellaneous income (expense)
|
|
|
49
|
|
|
|
(1,565
|
)
|
Interest charges
|
|
|
39,582
|
|
|
|
35,533
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
185,007
|
|
|
|
189,449
|
|
Income tax expense
|
|
|
70,881
|
|
|
|
60,446
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
1.22
|
|
|
$
|
1.41
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
1.22
|
|
|
$
|
1.40
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.335
|
|
|
$
|
0.330
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
92,518
|
|
|
|
90,895
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
92,853
|
|
|
|
91,192
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
2,168,882
|
|
|
$
|
2,286,388
|
|
Regulated transmission and storage segment
|
|
|
102,041
|
|
|
|
113,916
|
|
Natural gas marketing segment
|
|
|
1,236,423
|
|
|
|
1,496,153
|
|
Pipeline, storage and other segment
|
|
|
20,673
|
|
|
|
28,720
|
|
Intersegment eliminations
|
|
|
(294,901
|
)
|
|
|
(387,439
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
3,233,118
|
|
|
|
3,537,738
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
1,488,870
|
|
|
|
1,620,924
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
1,170,158
|
|
|
|
1,442,586
|
|
Pipeline, storage and other segment
|
|
|
3,002
|
|
|
|
5,559
|
|
Intersegment eliminations
|
|
|
(294,082
|
)
|
|
|
(386,594
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,367,948
|
|
|
|
2,682,475
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
865,170
|
|
|
|
855,263
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
240,950
|
|
|
|
254,417
|
|
Depreciation and amortization
|
|
|
106,919
|
|
|
|
106,576
|
|
Taxes, other than income
|
|
|
102,165
|
|
|
|
102,451
|
|
Asset impairments
|
|
|
|
|
|
|
2,078
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
450,034
|
|
|
|
465,522
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
415,136
|
|
|
|
389,741
|
|
Miscellaneous expense
|
|
|
(220
|
)
|
|
|
(1,866
|
)
|
Interest charges
|
|
|
78,290
|
|
|
|
74,524
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
336,626
|
|
|
|
313,351
|
|
Income tax expense
|
|
|
129,170
|
|
|
|
108,385
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
2.22
|
|
|
$
|
2.24
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
2.22
|
|
|
$
|
2.23
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.670
|
|
|
$
|
0.660
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
92,336
|
|
|
|
90,637
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
92,681
|
|
|
|
90,935
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
Charged to depreciation and amortization
|
|
|
106,919
|
|
|
|
106,576
|
|
Charged to other accounts
|
|
|
96
|
|
|
|
21
|
|
Deferred income taxes
|
|
|
44,097
|
|
|
|
97,892
|
|
Other
|
|
|
11,759
|
|
|
|
13,634
|
|
Net assets/liabilities from risk management activities
|
|
|
1,234
|
|
|
|
5,810
|
|
Net change in operating assets and liabilities
|
|
|
111,897
|
|
|
|
185,723
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
483,458
|
|
|
|
614,622
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(232,629
|
)
|
|
|
(221,330
|
)
|
Other, net
|
|
|
(946
|
)
|
|
|
(3,925
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(233,575
|
)
|
|
|
(225,255
|
)
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Net decrease in short-term debt
|
|
|
(75,907
|
)
|
|
|
(353,468
|
)
|
Net proceeds from issuance of long-term debt
|
|
|
|
|
|
|
446,188
|
|
Settlement of Treasury lock agreement
|
|
|
|
|
|
|
1,938
|
|
Repayment of long-term debt
|
|
|
(66
|
)
|
|
|
(625
|
)
|
Cash dividends paid
|
|
|
(62,550
|
)
|
|
|
(60,446
|
)
|
Issuance of common stock
|
|
|
8,590
|
|
|
|
12,414
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(129,933
|
)
|
|
|
46,001
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
119,950
|
|
|
|
435,368
|
|
Cash and cash equivalents at beginning of period
|
|
|
111,203
|
|
|
|
46,717
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
231,153
|
|
|
$
|
482,085
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
5
ATMOS
ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 2010
Atmos Energy Corporation (Atmos Energy or the
Company) and our subsidiaries are engaged primarily
in the regulated natural gas distribution and transmission and
storage businesses as well as certain other nonregulated
businesses. Our corporate headquarters and shared-services
function are located in Dallas, Texas and our customer support
centers are located in Amarillo and Waco, Texas.
Through our natural gas distribution business, we deliver
natural gas through sales and transportation arrangements to
over 3 million residential, commercial, public authority
and industrial customers through our six regulated natural gas
distribution divisions which cover service areas located in
12 states. In addition, we transport natural gas for others
through our distribution system. Our regulated activities also
include our regulated pipeline and storage operations, which
include the transportation of natural gas to our distribution
system and the management of our underground storage facilities.
Our natural gas distribution and regulated pipeline and storage
businesses are subject to federal and state regulation
and/or
regulation by local authorities in each of the states in which
our natural gas distribution divisions operate.
Our nonregulated businesses operate primarily in the Midwest and
Southeast and include our natural gas marketing operations and
pipeline, storage and other operations. These businesses are
operated through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc. (AEH), which is wholly owned by the
Company and based in Houston, Texas. Through our nonregulated
businesses, we primarily provide natural gas management and
marketing services to municipalities, other local gas
distribution companies and industrial customers and natural gas
transportation and storage services to certain of our natural
gas distribution divisions and third parties.
We operate the Company through the following four segments:
|
|
|
|
|
the
natural gas distribution segment
, which includes our
regulated natural gas distribution and related sales operations,
|
|
|
|
the
regulated transmission and storage segment
, which
includes our regulated pipeline and storage operations of the
Atmos Pipeline Texas Division,
|
|
|
|
the
natural gas marketing segment
, which includes a
variety of nonregulated natural gas management services and
|
|
|
|
the
pipeline, storage and other segment
, which is
comprised of our nonregulated natural gas gathering,
transmission and storage services.
|
|
|
2.
|
Unaudited
Financial Information
|
These consolidated interim-period financial statements have been
prepared in accordance with accounting principles generally
accepted in the United States on the same basis as those used
for the Companys audited consolidated financial statements
included in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. In the
opinion of management, all material adjustments (consisting of
normal recurring accruals) necessary for a fair presentation
have been made to the unaudited consolidated interim-period
financial statements. These consolidated interim-period
financial statements are condensed as permitted by the
instructions to
Form 10-Q
and should be read in conjunction with the audited consolidated
financial statements of Atmos Energy Corporation included in our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. Because of
seasonal and other factors, the results of operations for the
six-month period ended March 31, 2010 are not indicative of
our results of operations for the full 2010 fiscal year, which
ends September 30, 2010. We have evaluated subsequent
events from the March 31, 2010 balance sheet date through
the date these financial statements were filed with the
Securities and Exchange Commission (SEC).
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
No events have occurred subsequent to the balance sheet date
that would require recognition or disclosure in the financial
statements.
Significant
accounting policies
Our accounting policies are described in Note 2 to the
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009.
During the second quarter of fiscal 2010, we completed our
annual goodwill impairment assessment. Based on the assessment
performed, we determined that our goodwill was not impaired.
The Company adopted an accounting standard related to fair value
disclosures effective January 1, 2010. Effective
October 1, 2009, the Company adopted accounting standards
related to the measurement of liabilities at fair value, fair
value measurements of plan assets of a defined benefit pension
or other postretirement plan, the determination of participating
securities in the basic earnings per share calculation, business
combination accounting and the accounting and reporting for
minority interests. Except as indicated below, the adoption of
these standards did not have a material impact on our financial
position, results of operations or cash flows. There were no
other significant changes to our accounting policies during the
six months ended March 31, 2010.
Fair value disclosures
The Financial
Accounting Standards Board (FASB) issued guidance that requires
new disclosures surrounding fair value measurements to enhance
the existing disclosure requirements including
1) information about transfers in and out of Level 1
and Level 2 fair value measurements as well as a detailed
reconciliation of activity in Level 3 fair value
measurements; 2) a more detailed level of disaggregation
for each class of assets and liabilities; and 3) a
requirement to disclose information about the valuation
techniques and inputs used to measure fair value for both
recurring and nonrecurring fair value measurements that fall in
either Level 2 or Level 3. The new disclosures and
clarifications of existing disclosures are effective for interim
and annual reporting periods beginning after December 15,
2009, except for the disclosures related to the detailed
reconciliation of Level 3 fair value measurements, which
are effective for fiscal years beginning after December 15,
2010, and for interim periods within those fiscal years. As a
result of adopting this standard, we added a disclosure about
the valuation techniques and inputs we used to measure fair
value for our Level 2 recurring and nonrecurring fair value
measurements as of March 31, 2010 which is included in
Note 4. As of March 31, 2010, we did not have any
Level 3 fair value measurements.
Measurement of liabilities at fair value
When
a quoted price in an active market for an identical liability is
not available, we will be required to measure fair value using a
valuation technique that uses quoted prices of similar
liabilities, quoted prices of identical or similar liabilities
when traded as assets, or another valuation technique that is
consistent with U.S. generally accepted accounting
principles (GAAP), such as the income or market approach.
Additionally, when estimating the fair value of a liability, we
will not be required to include a separate input or adjustment
to other inputs relating to the existence of a restriction that
prevents our transfer of the liability.
Fair value measurements of plan assets of a defined benefit
pension or other postretirement plan
The FASB
issued guidance which requires employers to disclose annually
information about fair value measurements of the assets of a
defined benefit pension or other postretirement plan in a manner
similar to the requirements established for financial and
non-financial assets. The objectives of the required disclosures
are to provide users of financial statements with an
understanding of how investment allocation decisions are made,
the major categories of plan assets, the inputs and valuation
techniques used to measure fair value of plan assets and
significant concentrations of risk within plan assets. These
disclosures will appear in our
Form 10-K
for the year ending September 30, 2010.
The determination of participating securities in the basic
earnings per share calculation
The FASB issued
guidance related to determining whether instruments granted in
share-based payment transactions are
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
considered participating securities. The FASB determined that
non-vested share-based payments with a nonforfeitable right to
dividends or dividend equivalents are participating securities
and, as a result, companies with these types of participating
securities must use the two-class method to compute earnings per
share. Based on this guidance, the Company is required to
calculate earnings per share using the two-class method and will
include non-vested restricted stock and restricted stock units
for which vesting is only predicated upon the passage of time in
the basic earnings per share calculation. Non-vested restricted
stock and restricted stock units for which vesting is
predicated, in part upon the achievement of specified
performance targets, continue to be excluded from the
calculation of earnings per share. Although the provisions of
this standard were effective for us as of October 1, 2009,
prior-period earnings per share data must be recalculated and
adjusted accordingly. The calculation of basic and diluted
earnings per share pursuant to the two-class method is presented
in Note 6. The application of the two-class method resulted
in the following changes to basic and diluted earnings per share
for the three and six months ended March 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
March 31, 2009
|
|
March 31, 2009
|
|
|
(In thousands, except per share amounts)
|
|
Basic Earnings Per Share
|
|
|
|
|
|
|
|
|
Basic EPS as previously reported
|
|
$
|
1.42
|
|
|
$
|
2.26
|
|
Basic EPS as adjusted
|
|
$
|
1.41
|
|
|
$
|
2.24
|
|
Weighted average shares outstanding as previously
reported
|
|
|
90,895
|
|
|
|
90,637
|
|
Weighted average shares outstanding as adjusted
|
|
|
90,895
|
|
|
|
90,637
|
|
Diluted Earnings Per Share
|
|
|
|
|
|
|
|
|
Diluted EPS as previously reported
|
|
$
|
1.41
|
|
|
$
|
2.24
|
|
Diluted EPS as adjusted
|
|
$
|
1.40
|
|
|
$
|
2.23
|
|
Weighted average shares outstanding as previously
reported
|
|
|
91,567
|
|
|
|
91,311
|
|
Weighted average shares outstanding as adjusted
|
|
|
91,192
|
|
|
|
90,935
|
|
Business combination accounting
This new
pronouncement establishes new principles and requirements for
how the acquirer in a business combination recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed and any noncontrolling
interest in the acquiree at the acquisition date fair value.
This update significantly changes the accounting for business
combinations in a number of areas, including the treatment of
contingent consideration, preacquisition contingencies,
transaction costs and restructuring costs. In addition, under
the new guidelines, changes in an acquired entitys
deferred tax assets and uncertain tax positions after the
measurement period will impact current period income tax
expense. The provisions of this standard will apply to any
acquisitions we complete after October 1, 2009.
Accounting and reporting for minority interests
In December 2007, the FASB issued guidance related to the
accounting and reporting for minority interests, which will be
recharacterized as noncontrolling interests and classified as a
component of equity. This new consolidation method significantly
changes the accounting for transactions with minority interest
holders. As of March 31, 2010, Atmos Energy did not have
any transactions with minority interest holders.
Regulatory
assets and liabilities
Accounting principles generally accepted in the United States
require cost-based, rate-regulated entities that meet certain
criteria to reflect the authorized recovery of costs due to
regulatory decisions in their financial statements. As a result,
certain costs are permitted to be capitalized rather than
expensed because they can be recovered through rates. We record
certain costs as regulatory assets when future recovery through
customer rates is considered probable. Regulatory liabilities
are recorded when it is probable that revenues will
8
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be reduced for amounts that will be credited to customers
through the ratemaking process. Substantially all of our
regulatory assets are recorded as a component of deferred
charges and other assets and substantially all of our regulatory
liabilities are recorded as a component of deferred credits and
other liabilities. Deferred gas costs are recorded either in
other current assets or liabilities and the regulatory cost of
removal obligation is reported separately.
Significant regulatory assets and liabilities as of
March 31, 2010 and September 30, 2009 included the
following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
192,291
|
|
|
$
|
197,743
|
|
Merger and integration costs, net
|
|
|
6,938
|
|
|
|
7,161
|
|
Deferred gas costs
|
|
|
67,132
|
|
|
|
22,233
|
|
Environmental costs
|
|
|
913
|
|
|
|
866
|
|
Rate case costs
|
|
|
3,554
|
|
|
|
5,923
|
|
Deferred franchise fees
|
|
|
507
|
|
|
|
10,014
|
|
Deferred income taxes, net
|
|
|
639
|
|
|
|
639
|
|
Other
|
|
|
5,707
|
|
|
|
6,218
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
277,681
|
|
|
$
|
250,797
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
20,583
|
|
|
$
|
110,754
|
|
Deferred franchise fees
|
|
|
4,730
|
|
|
|
|
|
Regulatory cost of removal obligation
|
|
|
340,869
|
|
|
|
335,428
|
|
Other
|
|
|
6,358
|
|
|
|
7,960
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
372,540
|
|
|
$
|
454,142
|
|
|
|
|
|
|
|
|
|
|
Currently, our authorized rates do not include a return on
certain of our merger and integration costs; however, we recover
the amortization of these costs. Merger and integration costs,
net, are generally amortized on a straight-line basis over
estimated useful lives ranging up to 20 years.
Environmental costs have been deferred to be included in future
rate filings in accordance with rulings received from various
state regulatory commissions.
9
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the components of comprehensive
income, net of related tax, for the three-month and six-month
periods ended March 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
Unrealized holding gains (losses) on investments, net of tax
expense (benefit) of $408 and $(429) for the three months ended
March 31, 2010 and 2009 and of $798 and $(3,759) for the
six months ended March 31, 2010 and 2009
|
|
|
695
|
|
|
|
(862
|
)
|
|
|
1,359
|
|
|
|
(6,295
|
)
|
Other than temporary impairment of investments, net of tax
expense of $790 for the six months ended March 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,288
|
|
Amortization and unrealized gain on interest rate hedging
transactions, net of tax expense of $248 and $1,353 for the
three months ended March 31, 2010 and 2009 and $496 and
$1,835 for the six months ended March 31, 2010 and 2009
|
|
|
421
|
|
|
|
1,854
|
|
|
|
843
|
|
|
|
2,641
|
|
Net unrealized losses on commodity hedging transactions, net of
tax benefit of $6,321 and $7,524 for the three months ended
March 31, 2010 and 2009 and $2,067 and $21,341 for the six
months ended March 31, 2010 and 2009
|
|
|
(9,885
|
)
|
|
|
(9,771
|
)
|
|
|
(3,231
|
)
|
|
|
(32,315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
105,357
|
|
|
$
|
120,224
|
|
|
$
|
206,427
|
|
|
$
|
170,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss, net of tax, as of
March 31, 2010 and September 30, 2009 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
Unrealized holding gains on investments
|
|
$
|
3,819
|
|
|
$
|
2,460
|
|
Treasury lock agreements
|
|
|
(6,655
|
)
|
|
|
(7,498
|
)
|
Cash flow hedges
|
|
|
(18,377
|
)
|
|
|
(15,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(21,213
|
)
|
|
$
|
(20,184
|
)
|
|
|
|
|
|
|
|
|
|
We currently use financial instruments to mitigate commodity
price risk. Additionally, we periodically utilize financial
instruments to manage interest rate risk. The objectives and
strategies for using financial instruments have been tailored to
our regulated and nonregulated businesses. The accounting for
these financial instruments is fully described in Note 2 to
the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. Currently, we
utilize financial instruments in our natural gas distribution,
natural gas marketing and pipeline, storage and other segments.
However, our pipeline, storage and other segment uses financial
instruments acquired from Atmos Energy Marketing, LLC (AEM) on
the same terms that AEM received from an independent
counterparty. On a consolidated basis, these financial
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
instruments are reported in the natural gas marketing segment.
We currently do not manage commodity price risk with financial
instruments in our regulated transmission and storage segment.
Our financial instruments do not contain any credit-risk-related
or other contingent features that could cause accelerated
payments when our financial instruments are in net liability
positions.
Regulated
Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms
essentially insulate our natural gas distribution segment from
commodity price risk, our customers are exposed to the effect of
volatile natural gas prices. We manage this exposure through a
combination of physical storage, fixed-price forward contracts
and financial instruments, primarily
over-the-counter
swap and option contracts, in an effort to minimize the impact
of natural gas price volatility on our customers during the
winter heating season.
Our natural gas distribution gas supply department is
responsible for executing this segments commodity risk
management activities in conformity with regulatory
requirements. In jurisdictions where we are permitted to
mitigate commodity price risk through financial instruments, the
relevant regulatory authorities may establish the level of
heating season gas purchases that can be hedged. Historically,
if the regulatory authority does not establish this level, we
seek to hedge between 25 and 50 percent of anticipated
heating season gas purchases using financial instruments. For
the
2009-2010
heating season, in the jurisdictions where we are permitted to
utilize financial instruments, we hedged approximately
29 percent, or 26.9 Bcf of the planned winter flowing
gas requirements. We have not designated these financial
instruments as hedges.
The costs associated with and the gains and losses arising from
the use of financial instruments to mitigate commodity price
risk are included in our purchased gas adjustment mechanisms in
accordance with regulatory requirements. Therefore, changes in
the fair value of these financial instruments are initially
recorded as a component of deferred gas costs and recognized in
the consolidated statement of income as a component of purchased
gas cost when the related costs are recovered through our rates
and recognized in revenue in accordance with applicable
authoritative accounting guidance. Accordingly, there is no
earnings impact on our natural gas distribution segment as a
result of the use of financial instruments.
Nonregulated
Commodity Risk Management Activities
Our natural gas marketing segment, through AEM, aggregates and
purchases gas supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request.
We also perform asset optimization activities in both our
natural gas marketing segment and pipeline, storage and other
segment. Through asset optimization activities, we seek to
maximize the economic value associated with the storage and
transportation capacity we own or control. We attempt to meet
this objective by engaging in natural gas storage transactions
in which we seek to find and profit from pricing differences
that occur over time. We purchase physical natural gas and then
sell financial instruments at advantageous prices to lock in a
gross profit margin. Through the use of transportation and
storage services and financial instruments, we also seek to
capture gross profit margin through the arbitrage of pricing
differences that exist in various locations and by recognizing
pricing differences that occur over time. Over time, gains and
losses on the sale of storage gas inventory should be offset by
gains and losses on the financial instruments, resulting in the
realization of the economic gross profit margin we anticipated
at the time we structured the original transaction.
As a result of these activities, our nonregulated operations are
exposed to risks associated with changes in the market price of
natural gas. We manage our exposure to such risks through a
combination of physical storage and financial instruments,
including futures,
over-the-counter
and exchange-traded options and swap
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
contracts with counterparties. Futures contracts provide the
right to buy or sell the commodity at a fixed price in the
future. Option contracts provide the right, but not the
requirement, to buy or sell the commodity at a fixed price. Swap
contracts require receipt of payment for the commodity based on
the difference between a fixed price and the market price on the
settlement date.
We use financial instruments, designated as cash flow hedges of
anticipated purchases and sales at index prices, to mitigate the
commodity price risk in our natural gas marketing segment
associated with deliveries under fixed-priced forward contracts
to deliver gas to customers. These financial instruments have
maturity dates ranging from one to 52 months. We use
financial instruments, designated as fair value hedges, to hedge
our natural gas inventory used in our asset optimization
activities in our natural gas marketing and pipeline, storage
and other segments.
Also, in our natural gas marketing segment, we use storage swaps
and futures to capture additional storage arbitrage
opportunities that arise subsequent to the execution of the
original fair value hedge associated with our physical natural
gas inventory, basis swaps to insulate and protect the economic
value of our fixed price and storage books and various
over-the-counter
and exchange-traded options. These financial instruments have
not been designated as hedges.
Our nonregulated risk management activities are controlled
through various risk management policies and procedures. Our
Audit Committee has oversight responsibility for our
nonregulated risk management limits and policies. A risk
committee, comprised of corporate and business unit officers, is
responsible for establishing and enforcing our nonregulated risk
management policies and procedures.
Under our risk management policies, we seek to match our
financial instrument positions to our physical storage positions
as well as our expected current and future sales and purchase
obligations to maintain no open positions at the end of each
trading day. The determination of our net open position as of
any day, however, requires us to make assumptions as to future
circumstances, including the use of gas by our customers in
relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. Our operations can also be affected by
intraday fluctuations of gas prices, since the price of natural
gas purchased or sold for future delivery earlier in the day may
not be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on March 31, 2010, AEH
had net open positions (including existing storage) of
0.8 Bcf.
Interest
Rate Risk Management Activities
Currently, we are not managing interest rate risk with financial
instruments. However, in prior years, we periodically managed
interest rate risk by entering into Treasury lock agreements to
fix the Treasury yield component of the interest cost associated
with anticipated financings. These Treasury locks were settled
at various times at a cumulative net loss. These realized gains
and losses were recorded as a component of accumulated other
comprehensive income (loss) and are being recognized as a
component of interest expense over the life of the associated
notes from the date of settlement. The remaining amortization
periods for these Treasury locks extend through fiscal 2035.
However, the majority of the remaining amounts of these Treasury
locks will be recognized by the end of fiscal 2019.
Quantitative
Disclosures Related to Financial Instruments
The following tables present detailed information concerning the
impact of financial instruments on our condensed consolidated
balance sheet and income statements.
12
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of March 31, 2010, our financial instruments were
comprised of both long and short commodity positions. A long
position is a contract to purchase the commodity, while a short
position is a contract to sell the commodity. As of
March 31, 2010, we had net long/(short) commodity contracts
outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
Hedge
|
|
Gas
|
|
|
Gas
|
|
|
Storage and
|
|
Contract Type
|
|
Designation
|
|
Distribution
|
|
|
Marketing
|
|
|
Other
|
|
|
|
|
|
Quantity (MMcf)
|
|
|
Commodity contracts
|
|
Fair Value
|
|
|
|
|
|
|
(19,135
|
)
|
|
|
(1,010
|
)
|
|
|
Cash Flow
|
|
|
|
|
|
|
24,905
|
|
|
|
(700
|
)
|
|
|
Not designated
|
|
|
14,800
|
|
|
|
59,697
|
|
|
|
380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,800
|
|
|
|
65,467
|
|
|
|
(1,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Instruments on the Balance Sheet
The following tables present the fair value and balance sheet
classification of our financial instruments by operating segment
as of March 31, 2010 and September 30, 2009. As
required by authoritative accounting literature, the fair value
amounts below are presented on a gross basis and do not reflect
the netting of asset and liability positions permitted under the
terms of our master netting arrangements. Further, the amounts
below do not include $7.2 million and $11.7 million of
cash held on deposit in margin accounts as of March 31,
2010 and September 30, 2009 to collateralize certain
financial instruments. Therefore, these gross balances are not
indicative of either our actual credit exposure or net economic
exposure. Additionally, the amounts below will not be equal to
the amounts presented on our condensed consolidated balance
sheet, nor will they be equal to the fair value information
presented for our financial instruments in Note 4.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing
(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
49,314
|
|
|
$
|
49,314
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
5,899
|
|
|
|
5,899
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(51,648
|
)
|
|
|
(51,648
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(4,893
|
)
|
|
|
(4,893
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
(1,328
|
)
|
|
|
(1,328
|
)
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
281
|
|
|
|
40,314
|
|
|
|
40,595
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
4,692
|
|
|
|
4,692
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(22,016
|
)
|
|
|
(28,812
|
)
|
|
|
(50,828
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(639
|
)
|
|
|
(639
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(21,735
|
)
|
|
|
15,555
|
|
|
|
(6,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(21,735
|
)
|
|
$
|
14,227
|
|
|
$
|
(7,508
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment.
|
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing
(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
53,526
|
|
|
$
|
53,526
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
6,800
|
|
|
|
6,800
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(47,146
|
)
|
|
|
(47,146
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(999
|
)
|
|
|
(999
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
12,181
|
|
|
|
12,181
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
4,395
|
|
|
|
27,559
|
|
|
|
31,954
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
1,620
|
|
|
|
7,964
|
|
|
|
9,584
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(20,181
|
)
|
|
|
(19,657
|
)
|
|
|
(39,838
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(1,349
|
)
|
|
|
(1,349
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(14,166
|
)
|
|
|
14,517
|
|
|
|
351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(14,166
|
)
|
|
$
|
26,698
|
|
|
$
|
12,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment.
|
Impact of
Financial Instruments on the Income Statement
The following tables present the impact that financial
instruments had on our condensed consolidated income statement,
by operating segment, as applicable, for the three and six
months ended March 31, 2010 and 2009.
Hedge ineffectiveness for our natural gas marketing and pipeline
storage and other segments is recorded as a component of
unrealized gross profit and primarily results from differences
in the location and timing of the derivative instrument and the
hedged item. Hedge ineffectiveness could materially affect our
results of operations for the reported period. For the three
months ended March 31, 2010 and 2009 we recognized a gain
(loss) arising from fair value and cash flow hedge
ineffectiveness of $(4.9) million and $4.2 million.
For the six months ended March 31, 2010 and 2009 we
recognized a gain arising from fair value and cash flow hedge
ineffectiveness of $40.4 million and $24.6 million.
Additional information regarding ineffectiveness recognized in
the income statement is included in the tables below.
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value Hedges
The impact of commodity contracts designated as fair value
hedges and the related hedged item on our condensed consolidated
income statement for the three and six months ended
March 31, 2010 and 2009 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity contracts
|
|
$
|
30,926
|
|
|
$
|
2,535
|
|
|
$
|
33,461
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(34,969
|
)
|
|
|
(2,697
|
)
|
|
|
(37,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
(4,043
|
)
|
|
$
|
(162
|
)
|
|
$
|
(4,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(512
|
)
|
|
$
|
|
|
|
$
|
(512
|
)
|
Timing ineffectiveness
|
|
|
(3,531
|
)
|
|
|
(162
|
)
|
|
|
(3,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(4,043
|
)
|
|
$
|
(162
|
)
|
|
$
|
(4,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity contracts
|
|
$
|
19,870
|
|
|
$
|
2,105
|
|
|
$
|
21,975
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(18,562
|
)
|
|
|
(437
|
)
|
|
|
(18,999
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
1,308
|
|
|
$
|
1,668
|
|
|
$
|
2,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
2,327
|
|
|
$
|
|
|
|
$
|
2,327
|
|
Timing ineffectiveness
|
|
|
(1,019
|
)
|
|
|
1,668
|
|
|
|
649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,308
|
|
|
$
|
1,668
|
|
|
$
|
2,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity contracts
|
|
$
|
28,743
|
|
|
$
|
2,078
|
|
|
$
|
30,821
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
8,343
|
|
|
|
3,174
|
|
|
|
11,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
37,086
|
|
|
$
|
5,252
|
|
|
$
|
42,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(449
|
)
|
|
$
|
|
|
|
$
|
(449
|
)
|
Timing ineffectiveness
|
|
|
37,535
|
|
|
|
5,252
|
|
|
|
42,787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
37,086
|
|
|
$
|
5,252
|
|
|
$
|
42,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Commodity contracts
|
|
$
|
45,553
|
|
|
$
|
6,044
|
|
|
$
|
51,597
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(30,422
|
)
|
|
|
(1,990
|
)
|
|
|
(32,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
15,131
|
|
|
$
|
4,054
|
|
|
$
|
19,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
4,279
|
|
|
$
|
|
|
|
$
|
4,279
|
|
Timing ineffectiveness
|
|
|
10,852
|
|
|
|
4,054
|
|
|
|
14,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,131
|
|
|
$
|
4,054
|
|
|
$
|
19,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness arises from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the hedge instruments. Timing
ineffectiveness arises due to changes in the difference between
the spot price and the futures price, as well as the difference
between the timing of the settlement of the futures and the
valuation of the underlying physical commodity. As the commodity
contract nears the settlement date, spot to forward price
differences should converge, which should reduce or eliminate
the impact of this ineffectiveness on revenue.
Cash
Flow Hedges
The impact of cash flow hedges on our condensed consolidated
income statements for the three and six months ended
March 31, 2010 and 2009 is presented below. Note that this
presentation does not reflect the financial impact arising from
the hedged physical transaction. Therefore, this presentation is
not indicative of the economic gross profit we realized or will
realize when the underlying physical and financial transactions
are settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(10,685
|
)
|
|
$
|
2,129
|
|
|
$
|
(8,556
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(739
|
)
|
|
|
|
|
|
|
(739
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(11,424
|
)
|
|
|
2,129
|
|
|
|
(9,295
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(669
|
)
|
|
|
|
|
|
|
|
|
|
|
(669
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(669
|
)
|
|
$
|
(11,424
|
)
|
|
$
|
2,129
|
|
|
$
|
(9,964
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(48,585
|
)
|
|
$
|
16,170
|
|
|
$
|
(32,415
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
1,180
|
|
|
|
|
|
|
|
1,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(47,405
|
)
|
|
|
16,170
|
|
|
|
(31,235
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(1,269
|
)
|
|
$
|
(47,405
|
)
|
|
$
|
16,170
|
|
|
$
|
(32,504
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(34,556
|
)
|
|
$
|
2,883
|
|
|
$
|
(31,673
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(1,957
|
)
|
|
|
|
|
|
|
(1,957
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(36,513
|
)
|
|
|
2,883
|
|
|
|
(33,630
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(1,339
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,339
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(1,339
|
)
|
|
$
|
(36,513
|
)
|
|
$
|
2,883
|
|
|
$
|
(34,969
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Natural Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(76,829
|
)
|
|
$
|
24,139
|
|
|
$
|
(52,690
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
5,372
|
|
|
|
|
|
|
|
5,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(71,457
|
)
|
|
|
24,139
|
|
|
|
(47,318
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(2,538
|
)
|
|
$
|
(71,457
|
)
|
|
$
|
24,139
|
|
|
$
|
(49,856
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the gains and losses arising from
hedging transactions that were recognized as a component of
other comprehensive income (loss), net of taxes, for the three
and six months ended March 31, 2010 and 2009. The amounts
included in the table below exclude gains and losses arising
from ineffectiveness because those amounts are immediately
recognized in the income statement as incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
|
|
|
$
|
1,221
|
|
|
$
|
|
|
|
$
|
1,221
|
|
Forward commodity contracts
|
|
|
(15,104
|
)
|
|
|
(29,544
|
)
|
|
|
(22,551
|
)
|
|
|
(64,659
|
)
|
Recognition of losses in earnings due to settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
421
|
|
|
|
633
|
|
|
|
843
|
|
|
|
1,420
|
|
Forward commodity contracts
|
|
|
5,219
|
|
|
|
19,773
|
|
|
|
19,320
|
|
|
|
32,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss from hedging, net of
tax
(1)
|
|
$
|
(9,464
|
)
|
|
$
|
(7,917
|
)
|
|
$
|
(2,388
|
)
|
|
$
|
(29,674
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction.
|
Deferred losses recorded in AOCI associated with our treasury
lock agreements are recognized into earnings as they are
amortized, while deferred losses associated with commodity
contracts are recognized into earnings upon settlement. The
following amounts, net of deferred taxes, represent the expected
recognition in earnings of the deferred losses recorded in AOCI
associated with our financial instruments, based upon the fair
values of these financial instruments as of March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Commodity
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Next twelve months
|
|
$
|
(1,687
|
)
|
|
$
|
(14,830
|
)
|
|
$
|
(16,517
|
)
|
Thereafter
|
|
|
(4,968
|
)
|
|
|
(3,547
|
)
|
|
|
(8,515
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
(1)
|
|
$
|
(6,655
|
)
|
|
$
|
(18,377
|
)
|
|
$
|
(25,032
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction.
|
Financial
Instruments Not Designated as Hedges
The impact of financial instruments that have not been
designated as hedges on our condensed consolidated income
statements for the three and six months ended March 31,
2010 and 2009 is presented below. Note that this presentation
does not reflect the expected gains or losses arising from the
underlying physical transactions associated with these financial
instruments. Therefore, this presentation is not indicative of
the economic gross profit we realized when the underlying
physical and financial transactions were settled.
As discussed above, financial instruments used in our natural
gas distribution segment are not designated as hedges. However,
there is no earnings impact to our natural gas distribution
segment as a result of the use of these financial instruments
because the gains and losses arising from the use of these
financial instruments are recognized in the consolidated
statement of income as a component of purchased gas cost when
the related
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
costs are recovered through our rates and recognized in revenue.
Accordingly, the impact of these financial instruments is
excluded from this presentation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Natural gas marketing commodity contracts
|
|
$
|
(1,811
|
)
|
|
$
|
10,593
|
|
|
$
|
12,464
|
|
|
$
|
6,761
|
|
Pipeline, storage and other commodity contracts
|
|
|
(1,175
|
)
|
|
|
183
|
|
|
|
(168
|
)
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
(2,986
|
)
|
|
$
|
10,776
|
|
|
$
|
12,296
|
|
|
$
|
6,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Fair
Value Measurements
|
We report certain assets and liabilities at fair value, which is
defined as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between
market participants at the measurement date (exit price). We
record cash and cash equivalents, accounts receivable and
accounts payable at carrying value, which substantially
approximates fair value due to the short-term nature of these
assets and liabilities. For other financial assets and
liabilities, we primarily use quoted market prices and other
observable market pricing information to minimize the use of
unobservable pricing inputs in our measurements when determining
fair value. The methods used to determine fair value for our
assets and liabilities are fully described in Note 2 to the
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. During the
three and six months ended March 31, 2010, there were no
changes in these methods.
Effective October 1, 2009, the authoritative guidance
related to nonrecurring fair value measurements became effective
for us with respect to asset retirement obligations, most
nonfinancial assets and liabilities that may be acquired in a
business combination and impairment analyses performed for
nonfinancial assets. The adoption of the FASBs fair value
guidance for the reporting of these nonrecurring fair value
measurements did not have a material impact on our financial
position, results of operations or cash flows for the three and
six months ended March 31, 2010.
Although fair value measurements also apply to the valuation of
our pension and post-retirement plan assets, the current fair
value disclosure requirements are not applicable to our pension
and post-retirement plan assets. Accordingly, these plan assets
are not included in the tabular disclosures below. However,
similar disclosures about fair value measurements for our
pension and post-retirement plan assets will appear in our
Form 10-K
for the year ending September 30, 2010.
Quantitative
Disclosures
Financial
Instruments
The classification of our fair value measurements requires
judgment regarding the degree to which market data are
observable or corroborated by observable market data.
Authoritative accounting literature establishes a fair value
hierarchy that prioritizes the inputs used to measure fair value
based on observable and unobservable data. The hierarchy
categorizes the inputs into three levels, with the highest
priority given to unadjusted quoted prices in active markets for
identical assets and liabilities (Level 1), with the lowest
priority given to unobservable inputs (Level 3). The
following table summarizes, by level within the fair value
hierarchy, our assets and liabilities that were accounted for at
fair value on a recurring basis as of March 31, 2010.
Assets
19
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and liabilities are categorized in their entirety based on the
lowest level of input that is significant to the fair value
measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Netting and
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Cash
|
|
|
March 31,
|
|
|
|
(Level 1)
|
|
|
(Level
2)
(1)
|
|
|
(Level 3)
|
|
|
Collateral
(2)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
281
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
281
|
|
Natural gas marketing segment
|
|
|
31,459
|
|
|
|
68,760
|
|
|
|
|
|
|
|
(72,289
|
)
|
|
|
27,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
31,459
|
|
|
|
69,041
|
|
|
|
|
|
|
|
(72,289
|
)
|
|
|
28,211
|
|
Hedged portion of gas stored underground
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
73,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,655
|
|
Pipeline, storage and other
segment
(3)
|
|
|
3,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas stored underground
|
|
|
77,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77,499
|
|
Available-for-sale
securities
|
|
|
42,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
151,516
|
|
|
$
|
69,041
|
|
|
$
|
|
|
|
$
|
(72,289
|
)
|
|
$
|
148,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
22,016
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
22,016
|
|
Natural gas marketing segment
|
|
|
53,387
|
|
|
|
32,605
|
|
|
|
|
|
|
|
(79,488
|
)
|
|
|
6,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
53,387
|
|
|
$
|
54,621
|
|
|
$
|
|
|
|
$
|
(79,488
|
)
|
|
$
|
28,520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Our Level 2 measurements primarily consist of
non-exchange-traded financial instruments, such as
over-the-counter
options and swaps where market data for pricing is observable.
The fair values for these assets and liabilities are determined
using a market-based approach in which observable market prices
are adjusted for criteria specific to each instrument, such as
the strike price, notional amount or basis differences.
|
|
(2)
|
|
This column reflects adjustments to our gross financial
instrument assets and liabilities to reflect netting permitted
under our master netting agreements and authoritative accounting
literature. In addition, as of March 31, 2010, we had
$7.2 million of cash held in margin accounts used to
collateralize certain financial instruments which has been
reflected as a financial instrument asset.
|
|
(3)
|
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment.
|
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Fair Value Measures
Our debt is recorded at carrying value. The fair value of our
debt is determined using third party market value quotations.
The following table presents the carrying value and fair value
of our debt as of March 31, 2010:
|
|
|
|
|
|
|
March 31, 2010
|
|
|
(In thousands)
|
|
Carrying Amount
|
|
$
|
2,172,761
|
|
Fair Value
|
|
$
|
2,364,093
|
|
Long-term
debt
Long-term debt at March 31, 2010 and September 30,
2009 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Unsecured 7.375% Senior Notes, due May 2011
|
|
$
|
350,000
|
|
|
$
|
350,000
|
|
Unsecured 10% Notes, due December 2011
|
|
|
2,303
|
|
|
|
2,303
|
|
Unsecured 5.125% Senior Notes, due 2013
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 4.95% Senior Notes, due 2014
|
|
|
500,000
|
|
|
|
500,000
|
|
Unsecured 6.35% Senior Notes, due 2017
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 8.50% Senior Notes, due 2019
|
|
|
450,000
|
|
|
|
450,000
|
|
Unsecured 5.95% Senior Notes, due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A,
1995-2,
6.27%, due December 2010
|
|
|
10,000
|
|
|
|
10,000
|
|
Series A,
1995-1,
6.67%, due 2025
|
|
|
10,000
|
|
|
|
10,000
|
|
Unsecured 6.75% Debentures, due 2028
|
|
|
150,000
|
|
|
|
150,000
|
|
Rental property term note due in installments through 2013
|
|
|
458
|
|
|
|
524
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,172,761
|
|
|
|
2,172,827
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(3,155
|
)
|
|
|
(3,296
|
)
|
Current maturities
|
|
|
(10,131
|
)
|
|
|
(131
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,159,475
|
|
|
$
|
2,169,400
|
|
|
|
|
|
|
|
|
|
|
As noted above, our Series A,
1995-2,
6.27% medium term note will mature in December 2010;
accordingly, it has been classified within the current
maturities of long-term debt.
Short-term
debt
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply our customers needs could significantly affect our
borrowing requirements. Our short-term borrowings typically
reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
approximately $1.2 billion of working capital funding. At
March 31, 2010, there were no short-term debt borrowings
outstanding. At September 30, 2009, there was a total of
$72.6 million outstanding under our commercial paper
program. We also use intercompany credit facilities to
supplement the funding provided by these third-party committed
credit facilities. These facilities are described in greater
detail below.
Regulated
Operations
We fund our regulated operations as needed, primarily through
our commercial paper program and three committed revolving
credit facilities with third-party lenders that provide
approximately $800 million of working capital funding. The
first facility is a five-year $566.7 million unsecured
facility, expiring December 2011, that bears interest at a base
rate or at a LIBOR-based rate for the applicable interest
period, plus a spread ranging from 0.30 percent to
0.75 percent, based on the Companys credit ratings.
This credit facility serves as a backup liquidity facility for
our commercial paper program. At March 31, 2010, there were
no borrowings under this facility nor was there any commercial
paper outstanding.
The second facility is a $200 million unsecured
364-day
facility that expires October 22, 2010. The facility bears
interest at a base rate or at a LIBOR-based rate for the
applicable interest period, plus a spread ranging from
1.75 percent to 3.00 percent, based on the
Companys credit ratings. At March 31, 2010, there
were no borrowings outstanding under this facility.
The third facility is a $25 million unsecured facility that
bears interest at a daily negotiated rate, generally based on
the Federal Funds rate plus a variable margin. At March 31,
2010, there were no borrowings outstanding under this facility.
This facility expired on March 31, 2010 and was replaced
with a $25 million unsecured facility effective
April 1, 2010 that also bears interest at a daily
negotiated rate.
The availability of funds under these credit facilities is
subject to conditions specified in the respective credit
agreements, all of which we currently satisfy. These conditions
include our compliance with financial covenants and the
continued accuracy of representations and warranties contained
in these agreements. We are required by the financial covenants
in each of these facilities to maintain, at the end of each
fiscal quarter, a ratio of total debt to total capitalization of
no greater than 70 percent. At March 31, 2010, our
total-debt-to-total-capitalization ratio, as defined, was
51 percent. In addition, both the interest margin over the
Eurodollar rate and the fees that we pay on unused amounts under
each of these facilities are subject to adjustment depending
upon our credit ratings.
In addition to these third-party facilities, the Company has a
$200 million intercompany revolving credit facility
provided by AEH. This facility bears interest at the lower of
(i) the one-month LIBOR rate plus 0.45 percent or
(ii) the marginal borrowing rate available to the Company
on the date of borrowing. The marginal borrowing rate is defined
as the lower of (i) a rate based upon the lower of the
Prime Rate or the Eurodollar rate under the five year revolving
credit facility, (ii) a rate based upon the lower of the
Prime Rate or the Eurodollar rate under the
364-day
revolving credit facility or (iii) the lowest rate
outstanding under the commercial paper program. Applicable state
regulatory commissions have approved our use of this facility
through December 31, 2010. There was $20.5 million
outstanding under this facility at March 31, 2010.
Nonregulated
Operations
On December 10, 2009, AEM and the participating banks
amended and restated AEMs $450 million committed
revolving credit facility extending it to December 9, 2010.
AEM uses this facility primarily to issue letters of credit and,
on a less frequent basis, to borrow funds for gas purchases and
other working capital needs. At AEMs option, borrowings
made under the credit facility are based on a base rate or an
offshore rate, in each case plus an applicable margin. The base
rate is a floating rate equal to the higher of:
(a) 0.50 percent per annum above the latest Federal
Funds rate; (b) the per annum rate of interest established
by BNP Paribas from time to time as its prime rate
or base rate for U.S. dollar
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
loans; (c) an offshore rate (based on LIBOR with a
three-month interest period) as in effect from time to time; and
(d) the cost of funds rate which is the cost of
funds as reasonably determined by the administrative agent plus
0.50 percent. The offshore rate is a floating rate equal to
the higher of (a) an offshore rate based upon LIBOR for the
applicable interest period; and (b) a cost of
funds rate referred to above. In the case of both base
rate and offshore rate loans, the applicable margin ranges from
2.250 percent to 2.625 percent per annum, depending on
the excess tangible net worth of AEM, as defined in the credit
facility. This facility has swing line loan features, which
allow AEM to borrow, on a same day basis, an amount ranging from
$17 million to $27 million based on the terms of an
election within the agreement. This facility is collateralized
by substantially all of the assets of AEM and is guaranteed by
AEH.
At March 31, 2010, there were no borrowings outstanding
under this credit facility. However, at March 31, 2010, AEM
letters of credit totaling $42.0 million had been issued
under the facility, which reduced the amount available by a
corresponding amount. The amount available under this credit
facility is also limited by various covenants, including
covenants based on working capital. Under the most restrictive
covenant, the amount available to AEM under this credit facility
was $258.0 million at March 31, 2010.
AEM is required by the financial covenants in this facility to
maintain a ratio of total liabilities to tangible net worth that
does not exceed a maximum of 5 to 1. At March 31, 2010,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 0.96 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$75 million to $112.5 million. As defined in the
financial covenants, at March 31, 2010, AEMs net
working capital was $240.4 million and its tangible net
worth was $254.4 million.
To supplement borrowings under this facility, AEM has a
$300 million intercompany demand credit facility with AEH,
which bears interest at the greater of (i) the one-month
LIBOR rate plus 3.00 percent or (ii) the rate for
AEMs offshore borrowings under its committed credit
facility plus 0.75 percent. Amounts outstanding under this
facility are subordinated to AEMs committed credit
facility. There was $40.0 million outstanding under this
facility at March 31, 2010.
Finally, AEH has a $200 million intercompany demand credit
facility with AEC, which bears interest at greater of
(i) the one-month LIBOR rate plus 3.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. Applicable
state regulatory commissions have approved the new facility
through December 31, 2010. There were no borrowings
outstanding under this facility at March 31, 2010.
Shelf
Registration
On March 31, 2010, we filed a registration statement with
the SEC to issue, from time to time, up to $1.3 billion in
common stock
and/or
debt
securities available for issuance.
We had already received approvals from all requisite state
regulatory commissions to issue a total of $1.3 billion in
common stock
and/or
debt
securities under the new shelf registration statement, including
the carryforward of the $450 million of securities
remaining available for issuance under our shelf registration
statement filed with the SEC on March 23, 2009. Due to
certain restrictions imposed by one state regulatory commission
on our ability to issue securities under the new registration
statement, we will be able to issue a total of $950 million
in debt securities and $350 million in equity securities.
Debt
Covenants
In addition to the financial covenants described above, our
credit facilities and public indentures contain usual and
customary covenants for our business, including covenants
substantially limiting liens, substantial asset sales and
mergers.
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Additionally, our public debt indentures relating to our senior
notes and debentures, as well as our revolving credit
agreements, each contain a default provision that is triggered
if outstanding indebtedness arising out of any other credit
agreements in amounts ranging from in excess of $15 million
to in excess of $100 million becomes due by acceleration or
is not paid at maturity.
Further, AEMs credit agreement contains a cross-default
provision whereby AEM would be in default if it defaults on
other indebtedness, as defined, by at least $250 thousand in the
aggregate.
Finally, AEMs credit agreement contains a provision that
would limit the amount of credit available if Atmos Energy were
downgraded below an S&P rating of BBB and a Moodys
rating of Baa2. We have no other triggering events in our debt
instruments that are tied to changes in specified credit ratings
or stock price, nor have we entered into any transactions that
would require us to issue equity, based on our credit rating or
other triggering events.
We were in compliance with all of our debt covenants as of
March 31, 2010. If we were unable to comply with our debt
covenants, we would likely be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions.
As discussed in Note 2, since we have non-vested
share-based payments with a nonforfeitable right to dividends or
dividend equivalents (referred to as participating securities)
we are required to use the two-class method of computing
earnings per share as of October 1, 2009. The
Companys non-vested restricted stock and restricted stock
units, for which vesting is predicated solely on the passage of
time granted under the 1998 Long-Term Incentive Plan, are
considered to be participating securities. The calculation of
earnings per share using the two-class method excludes income
attributable to these participating securities from the
numerator and excludes the dilutive impact of those shares from
the denominator. The presentation of earnings per share for
previously reported periods has been adjusted to reflect the
retrospective adoption of this standard. Basic and diluted
earnings per share for the three and six months ended
March 31, 2010 and 2009 are calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Basic Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
Less: Income allocated to participating securities
|
|
|
1,142
|
|
|
|
1,183
|
|
|
|
2,088
|
|
|
|
1,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
112,984
|
|
|
$
|
127,820
|
|
|
$
|
205,368
|
|
|
$
|
203,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
92,518
|
|
|
|
90,895
|
|
|
|
92,336
|
|
|
|
90,637
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share Basic
|
|
$
|
1.22
|
|
|
$
|
1.41
|
|
|
$
|
2.22
|
|
|
$
|
2.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
112,984
|
|
|
$
|
127,820
|
|
|
$
|
205,368
|
|
|
$
|
203,149
|
|
Effect of dilutive stock options and other shares
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
112,987
|
|
|
$
|
127,823
|
|
|
$
|
205,373
|
|
|
$
|
203,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
92,518
|
|
|
|
90,895
|
|
|
|
92,336
|
|
|
|
90,637
|
|
Additional dilutive stock options and other shares
|
|
|
335
|
|
|
|
297
|
|
|
|
345
|
|
|
|
298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
92,853
|
|
|
|
91,192
|
|
|
|
92,681
|
|
|
|
90,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share Diluted
|
|
$
|
1.22
|
|
|
$
|
1.40
|
|
|
$
|
2.22
|
|
|
$
|
2.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
There were no
out-of-the-money
stock options excluded from the computation of diluted earnings
per share for the three and six months ended March 31, 2010
as their exercise price was less than the average market price
of the common stock during that period. There were approximately
260,000
out-of-the-money
stock options excluded from the computation of diluted earnings
per share for the three and six months ended March 31, 2009.
|
|
7.
|
Interim
Pension and Other Postretirement Benefit Plan
Information
|
The components of our net periodic pension cost for our pension
and other postretirement benefit plans for the three and six
months ended March 31, 2010 and 2009 are presented in the
following table. Most of these costs are recoverable through our
gas distribution rates; however, a portion of these costs is
capitalized into our gas distribution rate base. The remaining
costs are recorded as a component of operation and maintenance
expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,994
|
|
|
$
|
3,703
|
|
|
$
|
3,359
|
|
|
$
|
2,946
|
|
Interest cost
|
|
|
6,523
|
|
|
|
7,554
|
|
|
|
3,017
|
|
|
|
3,520
|
|
Expected return on assets
|
|
|
(6,320
|
)
|
|
|
(6,238
|
)
|
|
|
(615
|
)
|
|
|
(573
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
378
|
|
|
|
378
|
|
Amortization of prior service cost
|
|
|
(194
|
)
|
|
|
(183
|
)
|
|
|
(375
|
)
|
|
|
|
|
Amortization of actuarial loss
|
|
|
2,823
|
|
|
|
955
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
6,826
|
|
|
$
|
5,791
|
|
|
$
|
5,858
|
|
|
$
|
6,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
7,987
|
|
|
$
|
7,406
|
|
|
$
|
6,719
|
|
|
$
|
5,892
|
|
Interest cost
|
|
|
13,047
|
|
|
|
15,108
|
|
|
|
6,035
|
|
|
|
7,040
|
|
Expected return on assets
|
|
|
(12,640
|
)
|
|
|
(12,476
|
)
|
|
|
(1,230
|
)
|
|
|
(1,146
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
756
|
|
|
|
756
|
|
Amortization of prior service cost
|
|
|
(387
|
)
|
|
|
(366
|
)
|
|
|
(750
|
)
|
|
|
|
|
Amortization of actuarial loss
|
|
|
5,645
|
|
|
|
1,910
|
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
13,652
|
|
|
$
|
11,582
|
|
|
$
|
11,717
|
|
|
$
|
12,542
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three and six months ended March 31, 2010 and 2009
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Benefits
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Discount rate
|
|
|
5.52
|
%
|
|
|
7.57
|
%
|
|
|
5.52
|
%
|
|
|
7.57
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The discount rate used to compute the present value of a
plans liabilities generally is based on rates of
high-grade corporate bonds with maturities similar to the
average period over which the benefits will be paid. Generally,
our funding policy has been to contribute annually an amount in
accordance with the requirements of the Employee Retirement
Income Security Act of 1974. In accordance with the Pension
Protection Act of 2006 (PPA), we determined the funded status of
our plans as of January 1, 2010. Based upon this valuation,
we expect we will be required to contribute less than
$5 million to our pension plans by September 15, 2010.
We contributed $5.9 million to our other post-retirement
benefit plans during the six months ended March 31, 2010.
We expect to contribute a total of approximately
$12 million to these plans during fiscal 2010.
For our Supplemental Executive Retirement Plans, we own equity
securities that are classified as
available-for-sale
securities. These securities are reported at market value with
unrealized gains and losses shown as a component of accumulated
other comprehensive income (loss). We regularly evaluate the
performance of these investments on a fund by fund basis for
impairment, taking into consideration the funds purpose,
volatility and current returns. If a determination is made that
a decline in fair value is other than temporary, the related
fund is written down to its estimated fair value and the
other-than-temporary
impairment is recognized in the income statement.
Assets for the supplemental plans are held in separate rabbi
trusts and comprise the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Gross
|
|
|
|
|
|
|
Amortized
|
|
|
Unrealized
|
|
|
Unrealized
|
|
|
Fair
|
|
|
|
Cost
|
|
|
Gain
|
|
|
Loss
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
As of March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
29,306
|
|
|
$
|
5,132
|
|
|
$
|
|
|
|
$
|
34,438
|
|
Foreign equity mutual funds
|
|
|
4,753
|
|
|
|
927
|
|
|
|
|
|
|
|
5,680
|
|
Money market funds
|
|
|
2,440
|
|
|
|
|
|
|
|
|
|
|
|
2,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,499
|
|
|
$
|
6,059
|
|
|
$
|
|
|
|
$
|
42,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
26,012
|
|
|
$
|
3,012
|
|
|
$
|
|
|
|
$
|
29,024
|
|
Foreign equity mutual funds
|
|
|
4,047
|
|
|
|
893
|
|
|
|
|
|
|
|
4,940
|
|
Money market funds
|
|
|
7,735
|
|
|
|
|
|
|
|
|
|
|
|
7,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
37,794
|
|
|
$
|
3,905
|
|
|
$
|
|
|
|
$
|
41,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the six months ended March 31, 2009, we recorded a
$2.1 million noncash charge to impair certain
available-for-sale
investments due to deterioration of the market and the
uncertainty of a full recovery. We did not maintain any
investments that are in an unrealized loss position at
March 31, 2010.
|
|
8.
|
Commitments
and Contingencies
|
Litigation
and Environmental Matters
With respect to the specific litigation and
environmental-related matters or claims that were disclosed in
Note 12 to the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009, there were no
material changes in the status of such litigation and
environmental-related matters or claims during the six months
ended March 31, 2010. We continue to believe that the final
outcome of such litigation and environmental-related matters or
claims will not have a material adverse effect on our financial
condition, results of operations or cash flows.
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In addition, we are involved in other litigation and
environmental-related matters or claims that arise in the
ordinary course of our business. While the ultimate results of
such litigation or response actions to such
environmental-related matters or claims cannot be predicted with
certainty, we believe the final outcome of such litigation or
response actions will not have a material adverse effect on our
financial condition, results of operations or cash flows.
Purchase
Commitments
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At March 31, 2010, AEM was committed to
purchase 98.7 Bcf within one year, 8.1 Bcf within one
to three years and 2.5 Bcf after three years under indexed
contracts. AEM is committed to purchase 2.0 Bcf within one
year, 0.9 Bcf within one to three years and 0.1 Bcf
after three years under fixed price contracts with prices
ranging from $3.64 to $6.36 per Mcf. Purchases under these
contracts totaled $538.6 million and $431.5 million
for the three months ended March 31, 2010 and 2009 and
$892.7 million and $959.0 million for the six months
ended March 31, 2010 and 2009.
Our natural gas distribution divisions, except for our Mid-Tex
Division, maintain supply contracts with several vendors that
generally cover a period of up to one year. Commitments for
estimated base gas volumes are established under these contracts
on a monthly basis at contractually negotiated prices.
Commitments for incremental daily purchases are made as
necessary during the month in accordance with the terms of the
individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
and fixed prices. The estimated commitments under these
contracts as of March 31, 2010 are as follows (in
thousands):
|
|
|
|
|
2010
|
|
$
|
78,356
|
|
2011
|
|
|
150,999
|
|
2012
|
|
|
86,504
|
|
2013
|
|
|
6,564
|
|
2014
|
|
|
2,273
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
324,696
|
|
|
|
|
|
|
Our natural gas marketing and pipeline, storage and other
segments maintain long-term contracts related to storage and
transportation. The estimated contractual demand fees for
contracted storage and transportation under these contracts are
detailed in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. There were no
material changes to the estimated storage and transportation
fees for the six months ended March 31, 2010.
Regulatory
Matters
As previously described in Note 12 to the consolidated
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009, in December
2007, the Company received data requests from the Division of
Investigations of the Office of Enforcement of the Federal
Energy Regulatory Commission (the Commission) in
connection with its investigation into possible violations of
the Commissions posting and competitive bidding
regulations for pre-arranged released firm capacity on natural
gas pipelines.
After responding to two sets of data requests received from the
Commission, the Commission agreed to allow us to conduct our own
internal investigation into compliance with the
Commissions rules. We have
27
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
completed our internal investigation and submitted the results
to the Commission. During our investigation, we identified
certain non-compliant transactions, and we continue to fully
cooperate with the Commission as we work to resolve this matter.
We have accrued what we believe is an adequate amount for the
anticipated resolution of this proceeding. While the ultimate
resolution of this investigation cannot be predicted with
certainty, we believe that the final outcome will not have a
material adverse effect on our financial condition, results of
operations or cash flows.
As of March 31, 2010, rate cases were in progress in our
Kansas, Kentucky and Missouri service areas and annual rate
filing mechanisms were in progress in our Mid-Tex service area.
In addition, there were GRIP filings in progress in our Atmos
Pipeline Texas, Mid-Tex and West Texas divisions
along with other rate activity in our Georgia and Louisiana
service areas. These regulatory proceedings are discussed in
further detail below in
Managements Discussion and
Analysis Recent Ratemaking Developments
.
|
|
9.
|
Concentration
of Credit Risk
|
Information regarding our concentration of credit risk is
disclosed in Note 14 to the financial statements in our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. During the
six months ended March 31, 2010, there were no material
changes in our concentration of credit risk.
As discussed in Note 1 above, we operate the Company
through the following four segments:
|
|
|
|
|
The
natural gas distribution segment
, which includes our
regulated natural gas distribution and related sales operations.
|
|
|
|
The
regulated transmission and storage segment
, which
includes the regulated pipeline and storage operations of our
Atmos Pipeline Texas Division.
|
|
|
|
The
natural gas marketing segment
, which includes a
variety of nonregulated natural gas management services.
|
|
|
|
The
pipeline, storage and other segment
, which includes
our nonregulated natural gas gathering transmission and storage
services.
|
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in varying regulatory environments.
Although our natural gas distribution segment operations are
geographically dispersed, they are reported as a single segment
as each natural gas distribution division has similar economic
characteristics. The accounting policies of the segments are the
same as those described in the summary of significant accounting
policies found in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. We evaluate
performance based on net income or loss of the respective
operating units.
28
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income statements for the three and six month periods ended
March 31, 2010 and 2009 by segment are presented in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
1,365,736
|
|
|
$
|
21,643
|
|
|
$
|
545,985
|
|
|
$
|
6,902
|
|
|
$
|
|
|
|
$
|
1,940,266
|
|
Intersegment revenues
|
|
|
252
|
|
|
|
33,538
|
|
|
|
146,167
|
|
|
|
2,148
|
|
|
|
(182,105
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,365,988
|
|
|
|
55,181
|
|
|
|
692,152
|
|
|
|
9,050
|
|
|
|
(182,105
|
)
|
|
|
1,940,266
|
|
Purchased gas cost
|
|
|
980,603
|
|
|
|
|
|
|
|
685,672
|
|
|
|
1,369
|
|
|
|
(181,699
|
)
|
|
|
1,485,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
385,385
|
|
|
|
55,181
|
|
|
|
6,480
|
|
|
|
7,681
|
|
|
|
(406
|
)
|
|
|
454,321
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
87,542
|
|
|
|
20,248
|
|
|
|
6,531
|
|
|
|
3,173
|
|
|
|
(406
|
)
|
|
|
117,088
|
|
Depreciation and amortization
|
|
|
46,748
|
|
|
|
5,282
|
|
|
|
424
|
|
|
|
626
|
|
|
|
|
|
|
|
53,080
|
|
Taxes, other than income
|
|
|
55,531
|
|
|
|
2,949
|
|
|
|
747
|
|
|
|
386
|
|
|
|
|
|
|
|
59,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
189,821
|
|
|
|
28,479
|
|
|
|
7,702
|
|
|
|
4,185
|
|
|
|
(406
|
)
|
|
|
229,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
195,564
|
|
|
|
26,702
|
|
|
|
(1,222
|
)
|
|
|
3,496
|
|
|
|
|
|
|
|
224,540
|
|
Miscellaneous income
(expense)
|
|
|
776
|
|
|
|
(20
|
)
|
|
|
287
|
|
|
|
980
|
|
|
|
(1,974
|
)
|
|
|
49
|
|
Interest charges
|
|
|
29,256
|
|
|
|
7,954
|
|
|
|
2,820
|
|
|
|
1,526
|
|
|
|
(1,974
|
)
|
|
|
39,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
167,084
|
|
|
|
18,728
|
|
|
|
(3,755
|
)
|
|
|
2,950
|
|
|
|
|
|
|
|
185,007
|
|
Income tax expense (benefit)
|
|
|
64,353
|
|
|
|
6,658
|
|
|
|
(1,313
|
)
|
|
|
1,183
|
|
|
|
|
|
|
|
70,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
102,731
|
|
|
$
|
12,070
|
|
|
$
|
(2,442
|
)
|
|
$
|
1,767
|
|
|
$
|
|
|
|
$
|
114,126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
95,765
|
|
|
$
|
20,063
|
|
|
$
|
47
|
|
|
$
|
1,315
|
|
|
$
|
|
|
|
$
|
117,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
1,230,196
|
|
|
$
|
32,097
|
|
|
$
|
549,136
|
|
|
$
|
9,977
|
|
|
$
|
|
|
|
$
|
1,821,406
|
|
Intersegment revenues
|
|
|
224
|
|
|
|
27,137
|
|
|
|
159,522
|
|
|
|
2,295
|
|
|
|
(189,178
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,230,420
|
|
|
|
59,234
|
|
|
|
708,658
|
|
|
|
12,272
|
|
|
|
(189,178
|
)
|
|
|
1,821,406
|
|
Purchased gas cost
|
|
|
863,340
|
|
|
|
|
|
|
|
685,114
|
|
|
|
1,656
|
|
|
|
(188,755
|
)
|
|
|
1,361,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
367,080
|
|
|
|
59,234
|
|
|
|
23,544
|
|
|
|
10,616
|
|
|
|
(423
|
)
|
|
|
460,051
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
90,710
|
|
|
|
17,327
|
|
|
|
12,323
|
|
|
|
1,889
|
|
|
|
(509
|
)
|
|
|
121,740
|
|
Depreciation and amortization
|
|
|
47,541
|
|
|
|
5,006
|
|
|
|
396
|
|
|
|
507
|
|
|
|
|
|
|
|
53,450
|
|
Taxes, other than income
|
|
|
55,101
|
|
|
|
2,572
|
|
|
|
446
|
|
|
|
195
|
|
|
|
|
|
|
|
58,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
193,352
|
|
|
|
24,905
|
|
|
|
13,165
|
|
|
|
2,591
|
|
|
|
(509
|
)
|
|
|
233,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
173,728
|
|
|
|
34,329
|
|
|
|
10,379
|
|
|
|
8,025
|
|
|
|
86
|
|
|
|
226,547
|
|
Miscellaneous income
(expense)
|
|
|
835
|
|
|
|
283
|
|
|
|
118
|
|
|
|
2,060
|
|
|
|
(4,861
|
)
|
|
|
(1,565
|
)
|
Interest charges
|
|
|
28,821
|
|
|
|
7,349
|
|
|
|
3,461
|
|
|
|
677
|
|
|
|
(4,775
|
)
|
|
|
35,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
145,742
|
|
|
|
27,263
|
|
|
|
7,036
|
|
|
|
9,408
|
|
|
|
|
|
|
|
189,449
|
|
Income tax expense
|
|
|
44,166
|
|
|
|
7,798
|
|
|
|
3,688
|
|
|
|
4,794
|
|
|
|
|
|
|
|
60,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
101,576
|
|
|
$
|
19,465
|
|
|
$
|
3,348
|
|
|
$
|
4,614
|
|
|
$
|
|
|
|
$
|
129,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
84,618
|
|
|
$
|
28,303
|
|
|
$
|
88
|
|
|
$
|
954
|
|
|
$
|
|
|
|
$
|
113,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,168,422
|
|
|
$
|
41,485
|
|
|
$
|
1,006,806
|
|
|
$
|
16,405
|
|
|
$
|
|
|
|
$
|
3,233,118
|
|
Intersegment revenues
|
|
|
460
|
|
|
|
60,556
|
|
|
|
229,617
|
|
|
|
4,268
|
|
|
|
(294,901
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,168,882
|
|
|
|
102,041
|
|
|
|
1,236,423
|
|
|
|
20,673
|
|
|
|
(294,901
|
)
|
|
|
3,233,118
|
|
Purchased gas cost
|
|
|
1,488,870
|
|
|
|
|
|
|
|
1,170,158
|
|
|
|
3,002
|
|
|
|
(294,082
|
)
|
|
|
2,367,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
680,012
|
|
|
|
102,041
|
|
|
|
66,265
|
|
|
|
17,671
|
|
|
|
(819
|
)
|
|
|
865,170
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
183,575
|
|
|
|
37,827
|
|
|
|
15,286
|
|
|
|
5,081
|
|
|
|
(819
|
)
|
|
|
240,950
|
|
Depreciation and amortization
|
|
|
94,605
|
|
|
|
10,224
|
|
|
|
835
|
|
|
|
1,255
|
|
|
|
|
|
|
|
106,919
|
|
Taxes, other than income
|
|
|
93,521
|
|
|
|
6,216
|
|
|
|
1,682
|
|
|
|
746
|
|
|
|
|
|
|
|
102,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
371,701
|
|
|
|
54,267
|
|
|
|
17,803
|
|
|
|
7,082
|
|
|
|
(819
|
)
|
|
|
450,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
308,311
|
|
|
|
47,774
|
|
|
|
48,462
|
|
|
|
10,589
|
|
|
|
|
|
|
|
415,136
|
|
Miscellaneous income
(expense)
|
|
|
1,433
|
|
|
|
23
|
|
|
|
495
|
|
|
|
1,433
|
|
|
|
(3,604
|
)
|
|
|
(220
|
)
|
Interest charges
|
|
|
58,934
|
|
|
|
15,922
|
|
|
|
5,198
|
|
|
|
1,840
|
|
|
|
(3,604
|
)
|
|
|
78,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
250,810
|
|
|
|
31,875
|
|
|
|
43,759
|
|
|
|
10,182
|
|
|
|
|
|
|
|
336,626
|
|
Income tax expense
|
|
|
96,631
|
|
|
|
11,351
|
|
|
|
17,189
|
|
|
|
3,999
|
|
|
|
|
|
|
|
129,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
154,179
|
|
|
$
|
20,524
|
|
|
$
|
26,570
|
|
|
$
|
6,183
|
|
|
$
|
|
|
|
$
|
207,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
196,227
|
|
|
$
|
33,822
|
|
|
$
|
453
|
|
|
$
|
2,127
|
|
|
$
|
|
|
|
$
|
232,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,285,968
|
|
|
$
|
62,319
|
|
|
$
|
1,165,980
|
|
|
$
|
23,471
|
|
|
$
|
|
|
|
$
|
3,537,738
|
|
Intersegment revenues
|
|
|
420
|
|
|
|
51,597
|
|
|
|
330,173
|
|
|
|
5,249
|
|
|
|
(387,439
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,286,388
|
|
|
|
113,916
|
|
|
|
1,496,153
|
|
|
|
28,720
|
|
|
|
(387,439
|
)
|
|
|
3,537,738
|
|
Purchased gas cost
|
|
|
1,620,924
|
|
|
|
|
|
|
|
1,442,586
|
|
|
|
5,559
|
|
|
|
(386,594
|
)
|
|
|
2,682,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
665,464
|
|
|
|
113,916
|
|
|
|
53,567
|
|
|
|
23,161
|
|
|
|
(845
|
)
|
|
|
855,263
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
186,928
|
|
|
|
44,664
|
|
|
|
20,783
|
|
|
|
3,059
|
|
|
|
(1,017
|
)
|
|
|
254,417
|
|
Depreciation and amortization
|
|
|
94,680
|
|
|
|
9,961
|
|
|
|
797
|
|
|
|
1,138
|
|
|
|
|
|
|
|
106,576
|
|
Taxes, other than income
|
|
|
95,847
|
|
|
|
5,360
|
|
|
|
1,039
|
|
|
|
205
|
|
|
|
|
|
|
|
102,451
|
|
Asset impairments
|
|
|
1,776
|
|
|
|
232
|
|
|
|
56
|
|
|
|
14
|
|
|
|
|
|
|
|
2,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
379,231
|
|
|
|
60,217
|
|
|
|
22,675
|
|
|
|
4,416
|
|
|
|
(1,017
|
)
|
|
|
465,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
286,233
|
|
|
|
53,699
|
|
|
|
30,892
|
|
|
|
18,745
|
|
|
|
172
|
|
|
|
389,741
|
|
Miscellaneous income
(expense)
|
|
|
3,956
|
|
|
|
1,098
|
|
|
|
419
|
|
|
|
4,221
|
|
|
|
(11,560
|
)
|
|
|
(1,866
|
)
|
Interest charges
|
|
|
61,708
|
|
|
|
15,428
|
|
|
|
7,363
|
|
|
|
1,413
|
|
|
|
(11,388
|
)
|
|
|
74,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
228,481
|
|
|
|
39,369
|
|
|
|
23,948
|
|
|
|
21,553
|
|
|
|
|
|
|
|
313,351
|
|
Income tax expense
|
|
|
76,772
|
|
|
|
12,243
|
|
|
|
10,025
|
|
|
|
9,345
|
|
|
|
|
|
|
|
108,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
151,709
|
|
|
$
|
27,126
|
|
|
$
|
13,923
|
|
|
$
|
12,208
|
|
|
$
|
|
|
|
$
|
204,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
173,621
|
|
|
$
|
33,363
|
|
|
$
|
117
|
|
|
$
|
14,229
|
|
|
$
|
|
|
|
$
|
221,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at March 31, 2010 and
September 30, 2009 by segment is presented in the following
tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,811,548
|
|
|
$
|
697,167
|
|
|
$
|
7,229
|
|
|
$
|
74,531
|
|
|
$
|
|
|
|
$
|
4,590,475
|
|
Investment in subsidiaries
|
|
|
597,982
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(595,886
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
53,441
|
|
|
|
|
|
|
|
173,340
|
|
|
|
4,372
|
|
|
|
|
|
|
|
231,153
|
|
Assets from risk management activities
|
|
|
281
|
|
|
|
|
|
|
|
19,017
|
|
|
|
833
|
|
|
|
(833
|
)
|
|
|
19,298
|
|
Other current assets
|
|
|
571,092
|
|
|
|
14,726
|
|
|
|
278,909
|
|
|
|
71,287
|
|
|
|
(79,106
|
)
|
|
|
856,908
|
|
Intercompany receivables
|
|
|
507,490
|
|
|
|
|
|
|
|
|
|
|
|
176,488
|
|
|
|
(683,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,132,304
|
|
|
|
14,726
|
|
|
|
471,266
|
|
|
|
252,980
|
|
|
|
(763,917
|
)
|
|
|
1,107,359
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
1,147
|
|
|
|
|
|
|
|
|
|
|
|
1,147
|
|
Goodwill
|
|
|
571,592
|
|
|
|
132,300
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
738,603
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
8,913
|
|
|
|
|
|
|
|
|
|
|
|
8,913
|
|
Deferred charges and other assets
|
|
|
280,265
|
|
|
|
8,701
|
|
|
|
1,164
|
|
|
|
16,563
|
|
|
|
|
|
|
|
306,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,393,691
|
|
|
$
|
852,894
|
|
|
$
|
511,905
|
|
|
$
|
354,503
|
|
|
$
|
(1,359,803
|
)
|
|
$
|
6,753,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,338,843
|
|
|
$
|
191,724
|
|
|
$
|
107,420
|
|
|
$
|
298,838
|
|
|
$
|
(597,982
|
)
|
|
$
|
2,338,843
|
|
Long-term debt
|
|
|
2,159,148
|
|
|
|
|
|
|
|
|
|
|
|
327
|
|
|
|
|
|
|
|
2,159,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,497,991
|
|
|
|
191,724
|
|
|
|
107,420
|
|
|
|
299,165
|
|
|
|
(597,982
|
)
|
|
|
4,498,318
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
10,000
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
10,131
|
|
Short-term debt
|
|
|
20,475
|
|
|
|
|
|
|
|
40,000
|
|
|
|
|
|
|
|
(60,475
|
)
|
|
|
|
|
Liabilities from risk management activities
|
|
|
22,016
|
|
|
|
|
|
|
|
3,483
|
|
|
|
|
|
|
|
(833
|
)
|
|
|
24,666
|
|
Other current liabilities
|
|
|
657,020
|
|
|
|
7,961
|
|
|
|
239,894
|
|
|
|
41,376
|
|
|
|
(16,535
|
)
|
|
|
929,716
|
|
Intercompany payables
|
|
|
|
|
|
|
555,141
|
|
|
|
128,837
|
|
|
|
|
|
|
|
(683,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
709,511
|
|
|
|
563,102
|
|
|
|
412,214
|
|
|
|
41,507
|
|
|
|
(761,821
|
)
|
|
|
964,513
|
|
Deferred income taxes
|
|
|
501,447
|
|
|
|
93,550
|
|
|
|
(12,277
|
)
|
|
|
11,549
|
|
|
|
|
|
|
|
594,269
|
|
Noncurrent liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
3,854
|
|
|
|
|
|
|
|
|
|
|
|
3,854
|
|
Regulatory cost of removal obligation
|
|
|
317,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
317,203
|
|
Deferred credits and other liabilities
|
|
|
367,539
|
|
|
|
4,518
|
|
|
|
694
|
|
|
|
2,282
|
|
|
|
|
|
|
|
375,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,393,691
|
|
|
$
|
852,894
|
|
|
$
|
511,905
|
|
|
$
|
354,503
|
|
|
$
|
(1,359,803
|
)
|
|
$
|
6,753,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
and Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,703,471
|
|
|
$
|
672,829
|
|
|
$
|
7,112
|
|
|
$
|
55,691
|
|
|
$
|
|
|
|
$
|
4,439,103
|
|
Investment in subsidiaries
|
|
|
547,936
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(545,840
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
23,655
|
|
|
|
|
|
|
|
87,266
|
|
|
|
282
|
|
|
|
|
|
|
|
111,203
|
|
Assets from risk management activities
|
|
|
4,395
|
|
|
|
|
|
|
|
27,424
|
|
|
|
2,765
|
|
|
|
(2,941
|
)
|
|
|
31,643
|
|
Other current assets
|
|
|
499,155
|
|
|
|
17,017
|
|
|
|
157,846
|
|
|
|
112,551
|
|
|
|
(100,475
|
)
|
|
|
686,094
|
|
Intercompany receivables
|
|
|
552,408
|
|
|
|
|
|
|
|
|
|
|
|
128,104
|
|
|
|
(680,512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,079,613
|
|
|
|
17,017
|
|
|
|
272,536
|
|
|
|
243,702
|
|
|
|
(783,928
|
)
|
|
|
828,940
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
1,461
|
|
|
|
|
|
|
|
|
|
|
|
1,461
|
|
Goodwill
|
|
|
571,592
|
|
|
|
132,300
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
738,603
|
|
Noncurrent assets from risk management activities
|
|
|
1,620
|
|
|
|
|
|
|
|
12,415
|
|
|
|
6
|
|
|
|
(6
|
)
|
|
|
14,035
|
|
Deferred charges and other assets
|
|
|
290,327
|
|
|
|
11,932
|
|
|
|
1,065
|
|
|
|
18,300
|
|
|
|
|
|
|
|
321,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,194,559
|
|
|
$
|
834,078
|
|
|
$
|
316,775
|
|
|
$
|
328,128
|
|
|
$
|
(1,329,774
|
)
|
|
$
|
6,343,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,176,761
|
|
|
$
|
171,200
|
|
|
$
|
83,354
|
|
|
$
|
293,382
|
|
|
$
|
(547,936
|
)
|
|
$
|
2,176,761
|
|
Long-term debt
|
|
|
2,169,007
|
|
|
|
|
|
|
|
|
|
|
|
393
|
|
|
|
|
|
|
|
2,169,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,345,768
|
|
|
|
171,200
|
|
|
|
83,354
|
|
|
|
293,775
|
|
|
|
(547,936
|
)
|
|
|
4,346,161
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
131
|
|
Short-term debt
|
|
|
158,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(86,392
|
)
|
|
|
72,550
|
|
Liabilities from risk management activities
|
|
|
20,181
|
|
|
|
|
|
|
|
4,060
|
|
|
|
182
|
|
|
|
(2,941
|
)
|
|
|
21,482
|
|
Other current liabilities
|
|
|
510,749
|
|
|
|
9,251
|
|
|
|
116,078
|
|
|
|
19,167
|
|
|
|
(11,987
|
)
|
|
|
643,258
|
|
Intercompany payables
|
|
|
|
|
|
|
557,190
|
|
|
|
123,322
|
|
|
|
|
|
|
|
(680,512
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
689,872
|
|
|
|
566,441
|
|
|
|
243,460
|
|
|
|
19,480
|
|
|
|
(781,832
|
)
|
|
|
737,421
|
|
Deferred income taxes
|
|
|
477,352
|
|
|
|
92,250
|
|
|
|
(10,675
|
)
|
|
|
12,013
|
|
|
|
|
|
|
|
570,940
|
|
Noncurrent liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
Regulatory cost of removal obligation
|
|
|
321,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
321,086
|
|
Deferred credits and other liabilities
|
|
|
360,481
|
|
|
|
4,187
|
|
|
|
630
|
|
|
|
2,860
|
|
|
|
|
|
|
|
368,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,194,559
|
|
|
$
|
834,078
|
|
|
$
|
316,775
|
|
|
$
|
328,128
|
|
|
$
|
(1,329,774
|
)
|
|
$
|
6,343,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of March 31, 2010, the related
condensed consolidated statements of income for the three-month
and six-month periods ended March 31, 2010 and 2009, and
the condensed consolidated statements of cash flows for the
six-month periods ended March 31, 2010 and 2009. These
financial statements are the responsibility of the
Companys management.
We conducted our review in accordance with the standards of the
Public Company Accounting Oversight Board (United States). A
review of interim financial information consists principally of
applying analytical procedures and making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting
Oversight Board, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the condensed consolidated
financial statements referred to above for them to be in
conformity with U.S. generally accepted accounting
principles.
We have previously audited, in accordance with the standards of
the Public Company Accounting Oversight Board (United States),
the consolidated balance sheet of Atmos Energy Corporation as of
September 30, 2009, and the related consolidated statements
of income, shareholders equity, and cash flows for the
year then ended, not presented herein, and in our report dated
November 16, 2009, we expressed an unqualified opinion on
those consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated
balance sheet as of September 30, 2009, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Dallas, Texas
May 6, 2010
35
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
INTRODUCTION
The following discussion should be read in conjunction with the
condensed consolidated financial statements in this Quarterly
Report on
Form 10-Q
and Managements Discussion and Analysis in our Annual
Report on
Form 10-K
for the year ended September 30, 2009.
Cautionary
Statement for the Purposes of the Safe Harbor under the Private
Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on
Form 10-Q
may contain forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical fact included in
this Report are forward-looking statements made in good faith by
us and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation
Reform Act of 1995. When used in this Report, or any other of
our documents or oral presentations, the words
anticipate, believe,
estimate, expect, forecast,
goal, intend, objective,
plan, projection, seek,
strategy or similar words are intended to identify
forward-looking statements. Such forward-looking statements are
subject to risks and uncertainties that could cause actual
results to differ materially from those expressed or implied in
the statements relating to our strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties, which are
discussed in more detail in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009, include the
following: our ability to continue to access the credit markets
to satisfy our liquidity requirements; the impact of adverse
economic conditions on our customers; increased costs of
providing pension and postretirement health care benefits and
increased funding requirements; market risks beyond our control
affecting our risk management activities including market
liquidity, commodity price volatility, increasing interest rates
and counterparty creditworthiness; regulatory trends and
decisions, including the impact of rate proceedings before
various state regulatory commissions; increased federal
regulatory oversight and potential penalties; the impact of
environmental regulations on our business; the impact of
possible future additional regulatory and financial risks
associated with global warming and climate change on our
business; the concentration of our distribution, pipeline and
storage operations in Texas; adverse weather conditions; the
effects of inflation and changes in the availability and price
of natural gas; the capital-intensive nature of our gas
distribution business; increased competition from energy
suppliers and alternative forms of energy; the inherent hazards
and risks involved in operating our gas distribution business;
natural disasters, terrorist activities or other events; and
other risks and uncertainties discussed herein, all of which are
difficult to predict and many of which are beyond our control.
Accordingly, while we believe these forward-looking statements
to be reasonable, there can be no assurance that they will
approximate actual experience or that the expectations derived
from them will be realized. Further, we undertake no obligation
to update or revise any of our forward-looking statements
whether as a result of new information, future events or
otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the
regulated natural gas distribution and transportation and
storage businesses as well as other nonregulated natural gas
businesses. We distribute natural gas through sales and
transportation arrangements to over 3 million residential,
commercial, public authority and industrial customers throughout
our six regulated natural gas distribution divisions, which
cover service areas located in 12 states. In addition, we
transport natural gas for others through our regulated
distribution and pipeline systems.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local gas distribution companies and industrial customers
primarily in the Midwest and Southeast and natural gas
transportation and storage services to certain of our natural
gas distribution divisions and to third parties. Through our
asset optimization activities, we also seek to maximize the
economic value associated with the storage and transportation
capacity we own or control.
36
We operate the Company through the following four segments:
|
|
|
|
|
the
natural gas distribution segment
, which includes our
regulated natural gas distribution and related sales operations,
|
|
|
|
the
regulated transmission and storage segment
, which
includes the regulated pipeline and storage operations of the
Atmos Pipeline Texas Division,
|
|
|
|
the
natural gas marketing segment
, which includes a
variety of nonregulated natural gas management services and
|
|
|
|
the
pipeline, storage and other segment
, which is
comprised of our nonregulated natural gas gathering,
transmission and storage services.
|
CRITICAL
ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in
accordance with accounting principles generally accepted in the
United States. Preparation of these financial statements
requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses
and the related disclosures of contingent assets and
liabilities. We based our estimates on historical experience and
various other assumptions that we believe to be reasonable under
the circumstances. On an ongoing basis, we evaluate our
estimates, including those related to risk management and
trading activities, the allowance for doubtful accounts, legal
and environmental accruals, insurance accruals, pension and
postretirement obligations, deferred income taxes and the
valuation of goodwill, indefinite-lived intangible assets and
other long-lived assets. Actual results may differ from such
estimates.
Our critical accounting policies used in the preparation of our
consolidated financial statements are described in our Annual
Report on
Form 10-K
for the fiscal year ended September 30, 2009 and include
the following:
|
|
|
|
|
Regulation
|
|
|
|
Revenue Recognition
|
|
|
|
Allowance for Doubtful Accounts
|
|
|
|
Financial Instruments and Hedging Activities
|
|
|
|
Impairment Assessments
|
|
|
|
Pension and Other Postretirement Plans
|
|
|
|
Fair Value Measurements
|
Our critical accounting policies are reviewed quarterly by the
Audit Committee. There were no significant changes to these
critical accounting policies during the six months ended
March 31, 2010.
RESULTS
OF OPERATIONS
The second quarter is our most important earnings quarter, where
historically, we have earned about 64 percent of our annual
net income. For the three months ended March 31, 2010, we
reported net income of $114.1 million, or $1.22 per
diluted share compared with net income of $129.0 million,
or $1.40 per diluted share in the prior-year quarter.
During the three months ended March 31, 2010, we
experienced a 26 percent increase in consolidated
distribution throughput due to colder weather in most of our
service areas, which was partially offset by a 20 percent
decrease in consolidated throughput in our regulated
transmission and storage segment due to reduced demand and basis
spreads. In addition, net income for the second quarter includes
the positive impact of a state sales tax refund of
$4.5 million which contributed $0.05 per diluted share. The
results of our nonregulated operations also include noncash,
unrealized net losses of $25.5 million, or ($0.27) per
diluted share recognized during the quarter.
37
We reported net income of $207.5 million, or $2.22 per
diluted share for the six months ended March 31, 2010
compared with net income of $205.0 million, or $2.23 per
diluted share in the prior-year period. Regulated operations
contributed 84 percent of our net income during this period
with our nonregulated operations contributing the remaining
16 percent. The primary driver in the
year-over-year
increase in net income was due to our natural gas marketing
segment experiencing a significant increase in unrealized
margins. The favorable movement in our unrealized margins was
primarily the result of the
period-over-period
timing of storage withdrawal gains and the associated reversal
of unrealized gains into realized gains.
During the six months ended March 31, 2010,
colder-than-normal-weather
during the current year and recent improvements in rate designs
in our natural gas distribution segment partially offset the
decline in demand for natural gas, which contributed to a
25 percent
year-over-year
decrease in consolidated throughput in our regulated
transmission and storage segment and a three percent
year-over-year
decrease in consolidated sales volumes in our natural gas
marketing segment.
During the year, we continued to successfully access the capital
markets and received updated debt ratings from two rating
agencies. In October 2009, we renewed a $200 million
364-day
committed credit facility and in December 2009 we renewed a
$450 million
364-day
committed credit facility for our nonregulated operations. In
March 2010, Moodys upgraded our rating outlook from stable
to positive and affirmed the existing credit rating on our
senior long-term debt and commercial paper while S&P
affirmed our rating outlook as stable and our senior long-term
debt credit rating. The new credit facilities should help ensure
we have sufficient liquidity to fund our working capital needs,
while our credit ratings should help us continue to obtain
financing at a reasonable cost in the future.
The following table presents our consolidated financial
highlights for the three and six months ended March 31,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
March 31
|
|
March 31
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
(In thousands, except per share data)
|
|
Operating revenues
|
|
$
|
1,940,266
|
|
|
$
|
1,821,406
|
|
|
$
|
3,233,118
|
|
|
$
|
3,537,738
|
|
Gross profit
|
|
|
454,321
|
|
|
|
460,051
|
|
|
|
865,170
|
|
|
|
855,263
|
|
Operating expenses
|
|
|
229,781
|
|
|
|
233,504
|
|
|
|
450,034
|
|
|
|
465,522
|
|
Operating income
|
|
|
224,540
|
|
|
|
226,547
|
|
|
|
415,136
|
|
|
|
389,741
|
|
Miscellaneous income (expense)
|
|
|
49
|
|
|
|
(1,565
|
)
|
|
|
(220
|
)
|
|
|
(1,866
|
)
|
Interest charges
|
|
|
39,582
|
|
|
|
35,533
|
|
|
|
78,290
|
|
|
|
74,524
|
|
Income before income taxes
|
|
|
185,007
|
|
|
|
189,449
|
|
|
|
336,626
|
|
|
|
313,351
|
|
Income tax expense
|
|
|
70,881
|
|
|
|
60,446
|
|
|
|
129,170
|
|
|
|
108,385
|
|
Net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
Diluted net income per share
|
|
$
|
1.22
|
|
|
$
|
1.40
|
|
|
$
|
2.22
|
|
|
$
|
2.23
|
|
Our consolidated net income (loss) during the three and six
months ended March 31, 2010 and 2009 was earned in each of
our business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
102,731
|
|
|
$
|
101,576
|
|
|
$
|
1,155
|
|
Regulated transmission and storage segment
|
|
|
12,070
|
|
|
|
19,465
|
|
|
|
(7,395
|
)
|
Natural gas marketing segment
|
|
|
(2,442
|
)
|
|
|
3,348
|
|
|
|
(5,790
|
)
|
Pipeline, storage and other segment
|
|
|
1,767
|
|
|
|
4,614
|
|
|
|
(2,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
$
|
(14,877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
154,179
|
|
|
$
|
151,709
|
|
|
$
|
2,470
|
|
Regulated transmission and storage segment
|
|
|
20,524
|
|
|
|
27,126
|
|
|
|
(6,602
|
)
|
Natural gas marketing segment
|
|
|
26,570
|
|
|
|
13,923
|
|
|
|
12,647
|
|
Pipeline, storage and other segment
|
|
|
6,183
|
|
|
|
12,208
|
|
|
|
(6,025
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
|
$
|
2,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables segregate our consolidated net income
(loss) and diluted earnings per share between our regulated and
nonregulated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
114,801
|
|
|
$
|
121,041
|
|
|
$
|
(6,240
|
)
|
Nonregulated operations
|
|
|
(675
|
)
|
|
|
7,962
|
|
|
|
(8,637
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
114,126
|
|
|
$
|
129,003
|
|
|
$
|
(14,877
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.23
|
|
|
$
|
1.31
|
|
|
$
|
(0.08
|
)
|
Diluted EPS from nonregulated operations
|
|
|
(0.01
|
)
|
|
|
0.09
|
|
|
|
(0.10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
1.22
|
|
|
$
|
1.40
|
|
|
$
|
(0.18
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
174,703
|
|
|
$
|
178,835
|
|
|
$
|
(4,132
|
)
|
Nonregulated operations
|
|
|
32,753
|
|
|
|
26,131
|
|
|
|
6,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
207,456
|
|
|
$
|
204,966
|
|
|
$
|
2,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.87
|
|
|
$
|
1.95
|
|
|
$
|
(0.08
|
)
|
Diluted EPS from nonregulated operations
|
|
|
0.35
|
|
|
|
0.28
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
2.22
|
|
|
$
|
2.23
|
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Distribution Segment
The primary factors that impact the results of our natural gas
distribution operations are our ability to earn our authorized
rates of return, the cost of natural gas, competitive factors in
the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based
primarily on our ability to improve the rate design in our
various ratemaking jurisdictions by reducing or eliminating
regulatory lag and, ultimately, separating the recovery of our
approved margins from customer usage patterns. Improving rate
design is a long-term process and is further complicated by the
fact that we operate in multiple rate jurisdictions.
Seasonal weather patterns can also affect our natural gas
distribution operations. However, the effect of weather that is
above or below normal is substantially offset through weather
normalization adjustments,
39
known as WNA, which has been approved by state regulatory
commissions for approximately 90 percent of our residential
and commercial meters in the following states for the following
time periods:
|
|
|
Georgia
|
|
October May
|
Kansas
|
|
October May
|
Kentucky
|
|
November April
|
Louisiana
|
|
December March
|
Mississippi
|
|
November April
|
Tennessee
|
|
November April
|
Texas: Mid-Tex
|
|
November April
|
Texas: West Texas
|
|
October May
|
Virginia
|
|
January December
|
Our natural gas distribution operations are also affected by the
cost of natural gas. The cost of gas is passed through to our
customers without markup. Therefore, increases in the cost of
gas are offset by a corresponding increase in revenues.
Accordingly, we believe gross profit is a better indicator of
our financial performance than revenues. However, gross profit
in our Texas and Mississippi service areas includes franchise
fees and gross receipts taxes, which are calculated as a
percentage of revenue (inclusive of gas costs). Therefore, the
amount of these taxes included in revenues is influenced by the
cost of gas and the level of gas sales volumes. We record the
associated tax expense as a component of taxes, other than
income. Although changes in these revenue-related taxes arising
from changes in gas costs affect gross profit, over time the
impact is offset within operating income. Prior to
January 1, 2009, timing differences existed between the
recognition of revenue for franchise fees collected from our
customers and the recognition of expense of franchise taxes.
These timing differences had a significant temporary effect on
operating income in periods with volatile gas prices,
particularly in our Mid-Tex Division. Beginning January 1,
2009, changes in our franchise fee agreements in our Mid-Tex
Division became effective, which have significantly reduced the
impact of this timing difference. Although this timing
difference will still be present for gross receipts taxes, the
timing differences described above have been and should continue
to be less significant.
Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt expense and
may require us to increase borrowings under our credit
facilities resulting in higher interest expense. Finally, higher
gas costs, as well as competitive factors in the industry and
general economic conditions may cause customers to conserve or
use alternative energy sources.
40
Three
Months Ended March 31, 2010 compared with Three Months
Ended March 31, 2009
Financial and operational highlights for our natural gas
distribution segment for the three months ended March 31,
2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
385,385
|
|
|
$
|
367,080
|
|
|
$
|
18,305
|
|
Operating expenses
|
|
|
189,821
|
|
|
|
193,352
|
|
|
|
(3,531
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
195,564
|
|
|
|
173,728
|
|
|
|
21,836
|
|
Miscellaneous income
|
|
|
776
|
|
|
|
835
|
|
|
|
(59
|
)
|
Interest charges
|
|
|
29,256
|
|
|
|
28,821
|
|
|
|
435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
167,084
|
|
|
|
145,742
|
|
|
|
21,342
|
|
Income tax expense
|
|
|
64,353
|
|
|
|
44,166
|
|
|
|
20,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
102,731
|
|
|
$
|
101,576
|
|
|
$
|
1,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
158,530
|
|
|
|
121,560
|
|
|
|
36,970
|
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
39,294
|
|
|
|
35,061
|
|
|
|
4,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
197,824
|
|
|
|
156,621
|
|
|
|
41,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.48
|
|
|
$
|
(0.02
|
)
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
6.19
|
|
|
$
|
7.10
|
|
|
$
|
(0.91
|
)
|
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the three months ended March 31, 2010 and 2009. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
79,843
|
|
|
$
|
80,374
|
|
|
$
|
(531
|
)
|
Kentucky/Mid-States
|
|
|
31,000
|
|
|
|
27,404
|
|
|
|
3,596
|
|
Louisiana
|
|
|
22,831
|
|
|
|
19,782
|
|
|
|
3,049
|
|
West Texas
|
|
|
21,400
|
|
|
|
14,806
|
|
|
|
6,594
|
|
Mississippi
|
|
|
17,852
|
|
|
|
16,771
|
|
|
|
1,081
|
|
Colorado-Kansas
|
|
|
14,267
|
|
|
|
13,623
|
|
|
|
644
|
|
Other
|
|
|
8,371
|
|
|
|
968
|
|
|
|
7,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
195,564
|
|
|
$
|
173,728
|
|
|
$
|
21,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $18.3 million increase in natural gas distribution
gross profit primarily reflects rate adjustments and increased
throughput as follows:
|
|
|
|
|
$12.7 million net increase in rate adjustments, primarily
in the West Texas, Mid-Tex, Louisiana and Mississippi service
areas.
|
41
|
|
|
|
|
$8.7 million increase as a result of a 26 percent
increase in consolidated throughput primarily associated with
higher residential and commercial consumption and colder weather
in most of our service areas.
|
|
|
|
$4.9 million increase in revenue-related taxes primarily
due to higher revenues, on which the tax is calculated.
|
These increases were partially offset by:
|
|
|
|
|
$7.0 million decrease related to a prior year reversal of
an accrual for estimated unrecoverable gas costs that did not
recur in the current year.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, decreased
$3.5 million, primarily due to the following:
|
|
|
|
|
$7.4 million decrease due to a state sales tax
reimbursement received in March 2010.
|
|
|
|
$1.4 million decrease due to lower contract labor expense.
|
These decreases were partially offset by a $4.8 million
increase in employee-related expenses.
Additionally, results for the quarter ended March 31, 2009,
were favorably impacted by a one-time tax benefit of
$10.5 million. The benefit arose in the prior-year quarter
after the Company updated tax rates used to record deferred
taxes.
Six
Months Ended March 31, 2010 compared with Six Months Ended
March 31, 2009
Financial and operational highlights for our natural gas
distribution segment for the six months ended March 31,
2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
680,012
|
|
|
$
|
665,464
|
|
|
$
|
14,548
|
|
Operating expenses
|
|
|
371,701
|
|
|
|
379,231
|
|
|
|
(7,530
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
308,311
|
|
|
|
286,233
|
|
|
|
22,078
|
|
Miscellaneous income
|
|
|
1,433
|
|
|
|
3,956
|
|
|
|
(2,523
|
)
|
Interest charges
|
|
|
58,934
|
|
|
|
61,708
|
|
|
|
(2,774
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
250,810
|
|
|
|
228,481
|
|
|
|
22,329
|
|
Income tax expense
|
|
|
96,631
|
|
|
|
76,772
|
|
|
|
19,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
154,179
|
|
|
$
|
151,709
|
|
|
$
|
2,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
257,844
|
|
|
|
213,006
|
|
|
|
44,838
|
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
74,501
|
|
|
|
69,397
|
|
|
|
5,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
332,345
|
|
|
|
282,403
|
|
|
|
49,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.46
|
|
|
$
|
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
5.77
|
|
|
$
|
7.61
|
|
|
$
|
(1.84
|
)
|
42
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the six months ended March 31, 2010 and 2009. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
130,224
|
|
|
$
|
133,052
|
|
|
$
|
(2,828
|
)
|
Kentucky/Mid-States
|
|
|
48,803
|
|
|
|
46,429
|
|
|
|
2,374
|
|
Louisiana
|
|
|
36,238
|
|
|
|
34,366
|
|
|
|
1,872
|
|
West Texas
|
|
|
33,157
|
|
|
|
22,819
|
|
|
|
10,338
|
|
Mississippi
|
|
|
27,654
|
|
|
|
25,206
|
|
|
|
2,448
|
|
Colorado-Kansas
|
|
|
22,873
|
|
|
|
22,224
|
|
|
|
649
|
|
Other
|
|
|
9,362
|
|
|
|
2,137
|
|
|
|
7,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
308,311
|
|
|
$
|
286,233
|
|
|
$
|
22,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $14.5 million increase in natural gas distribution
gross profit primarily reflects rate adjustments and increased
throughput as follows:
|
|
|
|
|
$22.5 million net increase in rate adjustments, primarily
in the West Texas, Mid-Tex, Louisiana and Mississippi service
areas.
|
|
|
|
$11.0 million increase as a result of an 18 percent
increase in consolidated throughput primarily associated with
higher residential and commercial consumption and colder weather
in most of our service areas.
|
These increases were partially offset by:
|
|
|
|
|
$8.3 million decrease due to a non-recurring adjustment
recorded in the prior-year period to update the estimate for gas
delivered to customers but not yet billed to reflect base rate
changes.
|
|
|
|
$7.0 million decrease related to a prior year reversal of
an accrual for estimated unrecoverable gas costs that did not
recur in the current year.
|
|
|
|
$2.7 million decrease due to a decrease in revenue-related
taxes, primarily due to a decrease in revenues on which the tax
is calculated.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income and asset
impairments decreased $7.5 million, primarily due to the
following:
|
|
|
|
|
$7.4 million decrease due to a state sales tax
reimbursement received in March 2010.
|
|
|
|
|
|
$2.3 million decrease in taxes other than income due to
lower franchise fees and state gross receipts taxes.
|
|
|
|
|
|
$2.2 million decrease in contract labor expenses.
|
|
|
|
$1.8 million decrease due to the absence of an impairment
charge for
available-for-sale
securities recorded in December 2008.
|
|
|
|
$1.3 million decrease due to lower insurance premiums.
|
These decreases were partially offset by a $7.6 million
increase in employee-related expenses.
Miscellaneous income decreased $2.5 million due to lower
interest income. Interest charges decreased $2.8 million
primarily due to lower short-term debt balances and interest
rates.
Results for the six months ended March 31, 2009, were
favorably impacted by the aforementioned one-time tax benefit of
$10.5 million related to updated tax rates used to record
deferred taxes.
43
Recent
Ratemaking Developments
Significant ratemaking developments that occurred during the six
months ended March 31, 2010 are discussed below. The
amounts described below represent the operating income that was
requested or received in each rate filing, which may not
necessarily reflect the stated amount referenced in the final
order, as certain operating costs may have changed as a result
of a commissions or other governmental authoritys
final ruling.
Annual net operating income increases totaling
$19.0 million resulting from ratemaking activity became
effective in the six months ended March 31, 2010 as
summarized below:
|
|
|
|
|
|
|
Annual Increase to
|
|
Rate Action
|
|
Operating Income
|
|
|
|
(In thousands)
|
|
|
Rate case filings
|
|
$
|
9,195
|
|
Annual rate filing mechanisms
|
|
|
7,172
|
|
Other rate activity
|
|
|
2,630
|
|
|
|
|
|
|
|
|
$
|
18,997
|
|
|
|
|
|
|
Additionally, the following ratemaking efforts were in progress
during the second quarter of fiscal 2010 but had not been
completed as of March 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
|
|
Income
|
|
Division
|
|
Rate Action
|
|
Jurisdiction
|
|
Requested
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Atmos Pipeline Texas
|
|
GRIP
(1)
|
|
RRC
(2)
|
|
$
|
13,540
|
|
Colorado/Kansas
|
|
Rate Case
|
|
Kansas
|
|
|
6,015
|
|
Kentucky/Mid-States
|
|
PRP
(3)
|
|
Georgia
|
|
|
764
|
|
|
|
Rate
Case
(4)
|
|
Kentucky
|
|
|
9,486
|
|
|
|
Rate Case
|
|
Missouri
|
|
|
6,439
|
|
Louisiana
|
|
RSC
(5)
|
|
Louisiana
|
|
|
1,841
|
|
|
|
RSC
|
|
Louisiana
|
|
|
4,296
|
|
Mid-Tex
|
|
GRIP
(1)(6)
|
|
Dallas & RRC
|
|
|
2,985
|
|
|
|
Rate Review
Mechanism (RRM)
|
|
Settled Cities
|
|
|
56,827
|
|
West Texas
|
|
GRIP
(1)
|
|
RRC
|
|
|
370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
102,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Gas Reliability Infrastructure Program (GRIP) is a rate
adjustment that allows utilities to recover additional invested
capital without filing a full rate case.
|
|
(2)
|
|
Rate actions for the Atmos Pipeline Texas Division
are under the jurisdiction of the Railroad Commission of Texas
(RRC).
|
|
(3)
|
|
The Pipeline Replacement Program (PRP) surcharge relates to a
long-term cast iron replacement program.
|
|
(4)
|
|
The Company and Attorney General of the Commonwealth of Kentucky
have filed a joint settlement with the Kentucky Commission
requesting approval of a settlement in the amount of
$5.9 million. Additionally, the settlement recommends
moving bad debt recovery related to gas costs from base rates to
Gas Cost Adjustment rates for recovery ($0.7 million) and
approval of a pipeline replacement program.
|
|
(5)
|
|
The Louisiana Commission Staff recommended an increase of
$1.7 million effective April 1, 2010, which the
Commission accepted.
|
|
(6)
|
|
This GRIP filing is based on a Mid-Tex System-wide basis and
made concurrently with the City of Dallas and the RRC for
approval of their respective jurisdictional customers.
|
44
Additionally, in April 2010, our West Texas Division filed rate
review mechanism filings with the City of Amarillo, City of
Lubbock and West Texas Cities group for a combined increase of
$6.6 million.
Rate
Filings
A rate case is a formal request from Atmos Energy to a
regulatory authority to increase rates that are charged to our
customers. Rate cases may also be initiated when the regulatory
authorities request us to justify our rates. This process is
referred to as a show cause action. Adequate rates
are intended to provide for recovery of the Companys costs
as well as a fair rate of return to our shareholders and ensure
that we continue to deliver reliable, reasonably priced natural
gas service to our customers. The following table summarizes our
recent rate cases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Annual
|
|
|
Effective
|
|
|
|
|
Division
|
|
State
|
|
|
Operating Income
|
|
|
Date
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
2010 Rate Case Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
|
Georgia
|
|
|
$
|
2,935
|
|
|
|
3/31/2010
|
|
|
|
|
|
Mid-Tex
|
|
|
Texas
(1
|
)
|
|
|
2,963
|
|
|
|
01/26/2010
|
|
|
|
|
|
Colorado/Kansas
|
|
|
Colorado
|
|
|
|
1,900
|
|
|
|
01/04/2010
|
|
|
|
|
|
Kentucky/Mid-States
|
|
|
Virginia
|
|
|
|
1,397
|
|
|
|
11/23/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2010 Rate Case Filings
|
|
|
|
|
|
$
|
9,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In its final order, the RRC approved a $3.0 million
increase in operating income from customers in the
Dallas & Environs portion of the Mid-Tex Division. Net
of the GRIP 2008 rates that will be superseded, operating income
will increase $0.2 million. The ruling also provided for
regulatory accounting treatment for certain costs related to
storage assets and costs moving from our Mid-Tex Division within
our natural gas distribution segment to our regulated
transmission and storage segment.
|
GRIP
Filings
GRIP allows us to include in our rate base annually approved
capital costs incurred in the prior calendar year provided that
we file a complete rate case at least once every five years. The
Company had no GRIP filings approved as of March 31, 2010.
However, on April 20, 2010, the RRC approved an Atmos
Pipeline Texas GRIP filing in the amount of
$13.4 million.
Annual
Rate Filing Mechanisms
As an instrument to reduce regulatory lag, annual rate filing
mechanisms allow us to refresh our rates on a periodic basis
without filing a formal rate case. However, these filings still
involve discovery by the appropriate regulatory authorities
prior to the final determination of rates under these
mechanisms. We currently have annual rate filing mechanisms in
our Louisiana and Mississippi divisions and in significant
portions of our Mid-Tex and West Texas divisions. These
mechanisms are referred to as rate review mechanisms in our
Mid-Tex and West Texas divisions, stable rate filings in the
Mississippi Division and a rate
45
stabilization clause in the Louisiana Division. The following
table summarizes filings made under our various annual rate
filing mechanisms for the six months ended March 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
Test Year
|
|
|
Operating
|
|
|
Effective
|
|
Division
|
|
Jurisdiction
|
|
Ended
|
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2010 Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi
|
|
Mississippi
|
|
|
6/30/2009
|
|
|
$
|
3,183
|
|
|
|
12/15/2009
|
|
West Texas
|
|
Lubbock
|
|
|
12/31/2008
|
|
|
|
2,704
|
|
|
|
10/01/2009
|
|
West Texas
|
|
Amarillo
|
|
|
12/31/2008
|
|
|
|
1,285
|
|
|
|
10/01/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2010 Filings
|
|
|
|
|
|
|
|
$
|
7,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Ratemaking Activity
The following table summarizes other ratemaking activity during
the six months ended March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Effective
|
|
Division
|
|
Jurisdiction
|
|
Rate Activity
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
2010 Other Rate Activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky/Mid-States
|
|
Missouri
|
|
ISRS
(1)
|
|
$
|
563
|
|
|
|
03/02/2010
|
|
Colorado-Kansas
|
|
Kansas
|
|
Ad
Valorem
(2)
|
|
|
392
|
|
|
|
01/05/2010
|
|
|
|
Kansas
|
|
GSRS
(3)
|
|
|
766
|
|
|
|
12/12/2009
|
|
Kentucky/Mid-States
|
|
Georgia
|
|
PRP Surcharge
|
|
|
909
|
|
|
|
10/01/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2010 Other Rate Activity
|
|
|
|
|
|
$
|
2,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Infrastructure System Replacement Surcharge (ISRS) relates to
maintenance capital investments made since the previous rate
case.
|
|
(2)
|
|
The Ad Valorem filing relates to a collection of property taxes
in excess of the amount included in the Companys base
rates.
|
|
(3)
|
|
Gas System Reliability Surcharge (GSRS) relates to safety
related investments made since the previous rate case.
|
Regulated
Transmission and Storage Segment
Our regulated transmission and storage segment consists of the
regulated pipeline and storage operations of the Atmos
Pipeline Texas Division. The Atmos
Pipeline Texas Division transports natural gas to
our Mid-Tex Division and third parties and manages five
underground storage reservoirs in Texas. We also provide
ancillary services customary in the pipeline industry including
parking and lending arrangements and sales of inventory on hand.
Similar to our natural gas distribution segment, our regulated
transmission and storage segment is impacted by seasonal weather
patterns, competitive factors in the energy industry and
economic conditions in our service areas. Further, as the Atmos
Pipeline Texas Division operations supply all of the
natural gas for our Mid-Tex Division, the results of this
segment are highly dependent upon the natural gas requirements
of the Mid-Tex Division. Finally, as a regulated pipeline, the
operations of the Atmos Pipeline Texas Division may
be impacted by the timing of when costs and expenses are
incurred and when these costs and expenses are recovered through
its tariffs.
46
Three
Months Ended March 31, 2010 compared with Three Months
Ended March 31, 2009
Financial and operational highlights for our regulated
transmission and storage segment for the three months ended
March 31, 2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
33,214
|
|
|
$
|
27,061
|
|
|
$
|
6,153
|
|
Third-party transportation
|
|
|
16,335
|
|
|
|
23,846
|
|
|
|
(7,511
|
)
|
Storage and park and lend services
|
|
|
2,673
|
|
|
|
2,657
|
|
|
|
16
|
|
Other
|
|
|
2,959
|
|
|
|
5,670
|
|
|
|
(2,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
55,181
|
|
|
|
59,234
|
|
|
|
(4,053
|
)
|
Operating expenses
|
|
|
28,479
|
|
|
|
24,905
|
|
|
|
3,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
26,702
|
|
|
|
34,329
|
|
|
|
(7,627
|
)
|
Miscellaneous income (expense)
|
|
|
(20
|
)
|
|
|
283
|
|
|
|
(303
|
)
|
Interest charges
|
|
|
7,954
|
|
|
|
7,349
|
|
|
|
605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
18,728
|
|
|
|
27,263
|
|
|
|
(8,535
|
)
|
Income tax expense
|
|
|
6,658
|
|
|
|
7,798
|
|
|
|
(1,140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
12,070
|
|
|
$
|
19,465
|
|
|
$
|
(7,395
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
192,441
|
|
|
|
193,356
|
|
|
|
(915
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
98,418
|
|
|
|
123,285
|
|
|
|
(24,867
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $4.1 million decrease in regulated transmission and
storage gross profit was attributable primarily to the following
factors:
|
|
|
|
|
$3.5 million decrease due to lower transportation fees on
through-system deliveries due to narrower basis spreads.
|
|
|
|
$2.8 million decrease due to the absence of excess
inventory sales.
|
|
|
|
$2.6 million decrease in market-based demand fees, priority
reservation fees and compression activity associated with lower
throughput.
|
These decreases were partially offset by the following:
|
|
|
|
|
$3.2 million increase due to increased through system
volumes primarily associated with colder weather in our Mid-Tex
service area.
|
|
|
|
$1.5 million increase associated with our GRIP filings.
|
Operating expenses increased $3.6 million primarily due to
higher levels of pipeline maintenance activities and
employee-related expenses.
47
Six
Months Ended March 31, 2010 compared with Six Months Ended
March 31, 2009
Financial and operational highlights for our regulated
transmission and storage segment for the six months ended
March 31, 2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
59,925
|
|
|
$
|
51,413
|
|
|
$
|
8,512
|
|
Third-party transportation
|
|
|
31,577
|
|
|
|
49,212
|
|
|
|
(17,635
|
)
|
Storage and park and lend services
|
|
|
5,278
|
|
|
|
5,014
|
|
|
|
264
|
|
Other
|
|
|
5,261
|
|
|
|
8,277
|
|
|
|
(3,016
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
102,041
|
|
|
|
113,916
|
|
|
|
(11,875
|
)
|
Operating expenses
|
|
|
54,267
|
|
|
|
60,217
|
|
|
|
(5,950
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
47,774
|
|
|
|
53,699
|
|
|
|
(5,925
|
)
|
Miscellaneous income
|
|
|
23
|
|
|
|
1,098
|
|
|
|
(1,075
|
)
|
Interest charges
|
|
|
15,922
|
|
|
|
15,428
|
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
31,875
|
|
|
|
39,369
|
|
|
|
(7,494
|
)
|
Income tax expense
|
|
|
11,351
|
|
|
|
12,243
|
|
|
|
(892
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
20,524
|
|
|
$
|
27,126
|
|
|
$
|
(6,602
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
350,214
|
|
|
|
385,528
|
|
|
|
(35,314
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
194,356
|
|
|
|
259,143
|
|
|
|
(64,787
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $11.9 million decrease in regulated transmission and
storage gross profit was attributable primarily to the following
factors:
|
|
|
|
|
$7.5 million decrease due to lower transportation fees on
through-system deliveries due to narrower basis spreads.
|
|
|
|
$3.9 million decrease in market-based demand fees, priority
reservation fees and compression activity associated with lower
throughput.
|
|
|
|
$2.8 million decrease due to the absence of excess
inventory sales.
|
These decreases were partially offset by a $3.1 million
increase associated with our GRIP filings.
Operating expenses decreased $6.0 million primarily due to
lower levels of pipeline maintenance activities.
Natural
Gas Marketing Segment
Atmos Energy Marketing LLCs (AEM) primary business is to
aggregate and purchase gas supply, arrange transportation and
storage logistics and ultimately deliver gas to customers at
competitive prices. In addition, AEM utilizes proprietary and
customer-owned transportation and storage assets to provide
various services our customers request, including furnishing
natural gas supplies at fixed and market-based prices, contract
negotiation and administration, load forecasting, gas storage
acquisition and management services, transportation services,
peaking sales and balancing services, capacity utilization
strategies and gas price hedging through the use of financial
instruments (delivered gas business). As a result, AEMs
margins arise from the types of commercial transactions we have
structured with our customers and our ability to identify the
lowest cost alternative among the natural gas supplies,
transportation and markets to which it has access to serve those
customers.
48
AEM also seeks to enhance its gross profit margin by maximizing,
through asset optimization activities, the economic value
associated with the storage and transportation capacity we own
or control in our natural gas distribution and natural gas
marketing segments. We attempt to meet this objective by
engaging in natural gas storage transactions in which we seek to
find and profit through the arbitrage of pricing differences in
various locations and by recognizing pricing differences that
occur over time. This process involves purchasing physical
natural gas, storing it in the storage and transportation assets
to which AEM has access and selling financial instruments at
advantageous prices to lock in a gross profit margin.
AEM continually manages its net physical position to attempt to
increase the future economic profit that was created when the
original transaction was executed. Therefore, AEM may
subsequently change its originally scheduled storage injection
and withdrawal plans from one time period to another based on
market conditions and recognize any associated gains or losses
at that time. If AEM elects to accelerate the withdrawal of
physical gas, it will execute new financial instruments to hedge
the original financial instruments. If AEM elects to defer the
withdrawal of gas, it will reset its financial instruments by
settling the original financial instruments and executing new
financial instruments to correspond to the revised withdrawal
schedule.
We use financial instruments, designated as fair value hedges,
to hedge our natural gas inventory used in our natural gas
marketing storage activities. These financial instruments are
marked to market each month based upon the NYMEX price with
changes in fair value recognized as unrealized gains and losses
in the period of change. The hedged natural gas inventory is
marked to market at the end of each month based on the Gas Daily
index with changes in fair value recognized as unrealized gains
and losses in the period of change. Changes in the spreads
between the forward natural gas prices used to value the
financial hedges designated against our physical inventory and
the market (spot) prices used to value our physical storage
result in unrealized margins until the underlying physical gas
is withdrawn and the related financial instruments are settled.
Once the gas is withdrawn and the financial instruments are
settled, the previously unrealized margins associated with these
net positions are realized.
AEM also uses financial instruments to capture additional
storage arbitrage opportunities that may arise after the
original physical inventory is hedged and to attempt to insulate
and protect the economic value within its asset optimization
activities. Changes in fair value associated with these
financial instruments are recognized as a component of
unrealized margins until they are settled.
Due to the nature of these operations, natural gas prices have a
significant impact on our natural gas marketing operations.
Within our delivered gas business, higher natural gas prices may
adversely impact our accounts receivable collections, resulting
in higher bad debt expense and may require us to increase
borrowings under our credit facilities resulting in higher
interest expense. Higher gas prices, as well as competitive
factors in the industry and general economic conditions may also
cause customers to conserve or use alternative energy sources.
Within our asset optimization activities, higher gas prices
could also lead to increased borrowings under our credit
facilities resulting in higher interest expense.
Volatility in natural gas prices also has a significant impact
on our natural gas marketing segment. Increased price volatility
often has a significant impact on the spreads between market
(spot) prices and forward natural gas prices, which creates
opportunities to earn higher arbitrage spreads within our asset
optimization activities. However, increased volatility impacts
the amounts of unrealized margins recorded in our gross profit
and could impact the amount of cash required to collateralize
our risk management liabilities.
Three
Months Ended March 31, 2010 compared with Three Months
Ended March 31, 2009
Financial and operational highlights for our natural gas
marketing segment for the three months ended March 31, 2010
and 2009 are presented below. Gross profit margin consists
primarily of margins earned from the delivery of gas and related
services requested by our customers and margins earned from
asset optimization activities, which are derived from the
utilization of our proprietary and managed third-party storage
and transportation assets to capture favorable arbitrage spreads
through natural gas trading activities.
49
Unrealized margins represent the unrealized gains or losses on
our net physical gas position and the related financial
instruments used to manage commodity price risk as described
above. These margins fluctuate based upon changes in the spreads
between the physical and forward natural gas prices. Generally,
if the physical/financial spread narrows, we will record
unrealized gains or lower unrealized losses. If the
physical/financial spread widens, we will record unrealized
losses or lower unrealized gains. The magnitude of the
unrealized gains and losses is also contingent upon the levels
of our net physical position at the end of the reporting period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
17,126
|
|
|
$
|
23,165
|
|
|
$
|
(6,039
|
)
|
Asset
optimization
(1)
|
|
|
24,891
|
|
|
|
(2,073
|
)
|
|
|
26,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,017
|
|
|
|
21,092
|
|
|
|
20,925
|
|
Unrealized margins
|
|
|
(35,537
|
)
|
|
|
2,452
|
|
|
|
(37,989
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
6,480
|
|
|
|
23,544
|
|
|
|
(17,064
|
)
|
Operating expenses
|
|
|
7,702
|
|
|
|
13,165
|
|
|
|
(5,463
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(1,222
|
)
|
|
|
10,379
|
|
|
|
(11,601
|
)
|
Miscellaneous income
|
|
|
287
|
|
|
|
118
|
|
|
|
169
|
|
Interest charges
|
|
|
2,820
|
|
|
|
3,461
|
|
|
|
(641
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(3,755
|
)
|
|
|
7,036
|
|
|
|
(10,791
|
)
|
Income tax expense (benefit)
|
|
|
(1,313
|
)
|
|
|
3,688
|
|
|
|
(5,001
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(2,442
|
)
|
|
$
|
3,348
|
|
|
$
|
(5,790
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
123,877
|
|
|
|
123,066
|
|
|
|
811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
104,893
|
|
|
|
104,973
|
|
|
|
(80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
22.7
|
|
|
|
21.9
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Net of storage fees of $3.5 million and $2.9 million.
|
AEMs asset optimization activities contributed
59 percent to total realized margins during the second
quarter of fiscal 2010, with the delivered gas business
contributing the remaining 41 percent. The
$20.9 million increase in realized gross profit reflected:
|
|
|
|
|
A $26.9 million increase in asset optimization margins
primarily attributable to the timing of the settlement of open
positions. During the three months ended March 31, 2010,
AEM recognized the gains it had captured from its optimization
activities during the first quarter of fiscal 2010. In the prior
year, AEM recognized similar gains from its optimization
activities during the first quarter of fiscal 2009.
|
|
|
|
A $6.0 million decrease in realized delivered gas margins
due to lower
per-unit
margins as a result of narrowing basis spreads.
|
The increase in realized gross profit was more than offset by a
$38.0 million decrease in unrealized margins primarily due
to the realization during the current quarter of unrealized
gains that had been recorded in the first quarter of fiscal 2010.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income taxes,
decreased $5.5 million primarily due to a decrease in
employee and other administrative costs.
50
Six
Months Ended March 31, 2010 compared with Six Months Ended
March 31, 2009
Financial and operational highlights for our natural gas
marketing segment for the six months ended March 31, 2010
and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
33,213
|
|
|
$
|
41,718
|
|
|
$
|
(8,505
|
)
|
Asset
optimization
(1)
|
|
|
31,320
|
|
|
|
34,866
|
|
|
|
(3,546
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64,533
|
|
|
|
76,584
|
|
|
|
(12,051
|
)
|
Unrealized margins
|
|
|
1,732
|
|
|
|
(23,017
|
)
|
|
|
24,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
66,265
|
|
|
|
53,567
|
|
|
|
12,698
|
|
Operating expenses
|
|
|
17,803
|
|
|
|
22,675
|
|
|
|
(4,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
48,462
|
|
|
|
30,892
|
|
|
|
17,570
|
|
Miscellaneous income
|
|
|
495
|
|
|
|
419
|
|
|
|
76
|
|
Interest charges
|
|
|
5,198
|
|
|
|
7,363
|
|
|
|
(2,165
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
43,759
|
|
|
|
23,948
|
|
|
|
19,811
|
|
Income tax expense
|
|
|
17,189
|
|
|
|
10,025
|
|
|
|
7,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
26,570
|
|
|
$
|
13,923
|
|
|
$
|
12,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
226,138
|
|
|
|
233,724
|
|
|
|
(7,586
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
192,122
|
|
|
|
198,281
|
|
|
|
(6,159
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
22.7
|
|
|
|
21.9
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Net of storage fees of $6.0 million and $5.5 million.
|
AEMs delivered gas business contributed 51 percent to
total realized margins during the six months ended
March 31, 2010 with asset optimization activities
contributing the remaining 49 percent. The
$12.0 million decrease in realized gross profit reflected
the following:
|
|
|
|
|
$8.5 million decrease in realized delivered gas margins due
to lower
per-unit
margins as a result of narrowing basis spreads, combined with
lower delivered sales volumes.
Per-unit
margins were $0.15/Mcf in the current-year period compared with
$0.18/Mcf in the prior-year period, while delivered sales
volumes were three percent lower in the current-year period when
compared with the prior-year period.
|
|
|
|
$3.5 million decrease in asset optimization margins
primarily attributable to lower natural gas volatility in the
current-year period which created fewer opportunities to
optimize our storage assets.
|
The decrease in realized gross profit was more than offset by a
$24.7 million increase in unrealized margins due to the
period-over-period
timing of storage withdrawal gains and the associated reversal
of unrealized gains into realized gains.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income taxes and asset
impairments decreased $4.9 million primarily due to a
decrease in employee and other administrative costs.
Asset
Optimization Activities
AEM monitors the impact of its asset optimization efforts by
estimating the gross profit, before associated storage fees,
that it captured through the purchase and sale of physical
natural gas and the execution of the
51
associated financial instruments. This economic value, combined
with the effect of the future reversal of unrealized gains or
losses currently recognized in the income statement, is referred
to as the potential gross profit.
We define potential gross profit as the change in AEMs
gross profit from asset optimization activities in future
periods if its optimization efforts are executed as planned.
This amount does not include other operating expenses and
associated income taxes that will be incurred to realize this
amount. Therefore, it does not represent an estimated increase
in future net income. There is no assurance that the economic
value or the potential gross profit will be fully realized in
the future.
We consider this measure a non-GAAP financial measure as it is
calculated using both forward-looking storage
injections/withdrawals and hedge settlement estimates and
historical financial information. This measure is presented
because we believe it provides a more comprehensive view to
investors of our asset optimization efforts and thus a better
understanding of these activities than would be presented by
GAAP measures alone. Because there is no assurance that the
economic value or potential gross profit will be realized in the
future, corresponding future GAAP amounts are not available.
The following table presents AEMs economic value and its
potential gross profit (loss) at March 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions, unless otherwise noted)
|
|
|
Economic value
|
|
$
|
0.6
|
|
|
$
|
33.4
|
|
Associated unrealized (gains) losses
|
|
|
7.5
|
|
|
|
(2.4
|
)
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
8.1
|
|
|
|
31.0
|
|
Related
fees
(1)
|
|
|
(13.8
|
)
|
|
|
(16.0
|
)
|
|
|
|
|
|
|
|
|
|
Potential gross profit (loss)
|
|
$
|
(5.7
|
)
|
|
$
|
15.0
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
22.7
|
|
|
|
21.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Related fees represent AEMs contractual costs to acquire
the storage capacity utilized in its asset optimization
operations. The fees primarily consist of demand fees and
contractual obligations to sell gas below market index prices in
exchange for the right to manage and optimize third party
storage assets for the positions AEM has entered into as of
March 31, 2010 and 2009.
|
During the six months ended March 31, 2010, AEMs
economic value decreased from $28.6 million, or $2.07/Mcf
at September 30, 2009 to $0.6 million, or $0.02/Mcf.
This compares unfavorably to AEMs economic value at
March 31, 2009 of $33.4 million, or $1.53/Mcf.
Early in the first quarter of fiscal 2010, AEM withdrew gas and
realized previously captured spread values. As current cash
prices declined during the first fiscal quarter, AEM injected
gas and rolled positions into the second fiscal quarter to
increase economic value. These positions were settled in the
second fiscal quarter and the associated economic value was
realized. However, cash prices continued to fall and weak market
fundamentals created limited opportunities to capture economic
value. Therefore, AEM injected additional gas into storage.
However, as of March 31, 2010, AEM had established just a
limited number of positions as it believes future market
conditions will create improved opportunities to capture spread
values.
The economic value is based upon planned storage injection and
withdrawal schedules and its realization is contingent upon the
execution of this plan, weather and other execution factors.
Since AEM actively manages and optimizes its portfolio to
attempt to enhance the future profitability of its storage
position, it may change its scheduled storage injection and
withdrawal plans from one time period to another based on market
conditions. Therefore, we cannot ensure that the economic value
or the potential gross profit calculated as of March 31,
2010 will be fully realized in the future nor can we predict in
what time periods such realization
52
may occur. Further, if we experience operational or other issues
which limit our ability to optimally manage our stored gas
positions, our earnings could be adversely impacted.
Pipeline,
Storage and Other Segment
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS is
engaged in nonregulated transmission, storage and natural
gas-gathering services. Its primary asset is a proprietary
21 mile pipeline located in New Orleans, Louisiana that is
primarily used to aggregate gas supply for our regulated natural
gas distribution division in Louisiana, our natural gas
marketing segment, and, on a more limited basis, for third
parties. APS also owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
additional pipeline capacity to meet customer demand during peak
periods.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are with regulated affiliates of the Company
which have been approved by applicable state regulatory
commissions. Generally, these asset management plans require APS
to share with our regulated customers a portion of the profits
earned from these arrangements. APS also seeks to maximize the
economic value associated with the storage and transportation
capacity it owns or controls by engaging in natural gas storage
transactions in which it seeks to find and profit from the
pricing differences that occur over time.
Results for this segment are primarily impacted by seasonal
weather patterns and, similar to our natural gas marketing
segment, volatility in the natural gas markets. Additionally,
this segments results include an unrealized component as
APS hedges its risk associated with its asset optimization
activities.
Three
Months Ended March 31, 2010 compared with Three Months
Ended March 31, 2009
Financial and operational highlights for our pipeline, storage
and other segment for the three months ended March 31, 2010
and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Asset optimization
|
|
$
|
7,392
|
|
|
$
|
15,157
|
|
|
$
|
(7,765
|
)
|
Storage and transportation services
|
|
|
3,093
|
|
|
|
3,312
|
|
|
|
(219
|
)
|
Other
|
|
|
1,200
|
|
|
|
350
|
|
|
|
850
|
|
Unrealized margins
|
|
|
(4,004
|
)
|
|
|
(8,203
|
)
|
|
|
4,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
7,681
|
|
|
|
10,616
|
|
|
|
(2,935
|
)
|
Operating expenses
|
|
|
4,185
|
|
|
|
2,591
|
|
|
|
1,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
3,496
|
|
|
|
8,025
|
|
|
|
(4,529
|
)
|
Miscellaneous income
|
|
|
980
|
|
|
|
2,060
|
|
|
|
(1,080
|
)
|
Interest charges
|
|
|
1,526
|
|
|
|
677
|
|
|
|
849
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
2,950
|
|
|
|
9,408
|
|
|
|
(6,458
|
)
|
Income tax expense
|
|
|
1,183
|
|
|
|
4,794
|
|
|
|
(3,611
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,767
|
|
|
$
|
4,614
|
|
|
$
|
(2,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit from our pipeline, storage and other segment
decreased $2.9 million primarily due to the following:
|
|
|
|
|
$6.5 million decrease in margins earned from utilizing
assets subject to APS asset management plans due to fewer
trading opportunities this year compared to the prior-year
period which created a less volatile natural gas market.
|
|
|
|
$1.8 million decrease in basis gains earned from utilizing
leased capacity.
|
|
|
|
$4.2 million increase in unrealized margins associated with
our asset optimization activities.
|
53
Operating expenses increased $1.6 million primarily due to
legal and other administrative costs.
Six
Months Ended March 31, 2010 compared with Six Months Ended
March 31, 2009
Financial and operational highlights for our pipeline, storage
and other segment for the six months ended March 31, 2010
and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Asset optimization
|
|
$
|
7,489
|
|
|
$
|
20,624
|
|
|
$
|
(13,135
|
)
|
Storage and transportation services
|
|
|
6,427
|
|
|
|
6,627
|
|
|
|
(200
|
)
|
Other
|
|
|
1,144
|
|
|
|
1,339
|
|
|
|
(195
|
)
|
Unrealized margins
|
|
|
2,611
|
|
|
|
(5,429
|
)
|
|
|
8,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
17,671
|
|
|
|
23,161
|
|
|
|
(5,490
|
)
|
Operating expenses
|
|
|
7,082
|
|
|
|
4,416
|
|
|
|
2,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
10,589
|
|
|
|
18,745
|
|
|
|
(8,156
|
)
|
Miscellaneous income
|
|
|
1,433
|
|
|
|
4,221
|
|
|
|
(2,788
|
)
|
Interest charges
|
|
|
1,840
|
|
|
|
1,413
|
|
|
|
427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
10,182
|
|
|
|
21,553
|
|
|
|
(11,371
|
)
|
Income tax expense
|
|
|
3,999
|
|
|
|
9,345
|
|
|
|
(5,346
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
6,183
|
|
|
$
|
12,208
|
|
|
$
|
(6,025
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit from our pipeline, storage and other segment
decreased $5.5 million primarily due to the following:
|
|
|
|
|
$6.4 million decrease from lower margins earned on storage
optimization activities.
|
|
|
|
$3.7 million decrease in basis gains earned from utilizing
leased capacity.
|
|
|
|
$3.0 million decrease from lower margins earned on asset
management plans.
|
|
|
|
$8.0 million increase in unrealized margins associated with
our asset optimization activities.
|
Operating expenses increased $2.7 million primarily due to
the following:
|
|
|
|
|
$1.4 million increase in other administrative costs.
|
|
|
|
$0.7 million increase in employee costs.
|
|
|
|
$0.3 million increase in property taxes.
|
Miscellaneous income decreased $2.8 million due to lower
interest expense incurred by this segment.
Liquidity
and Capital Resources
The liquidity required to fund our working capital, capital
expenditures and other cash needs is provided from a variety of
sources, including internally generated funds and borrowings
under our commercial paper program and bank credit facilities.
Additionally, we have various uncommitted trade credit lines
with our gas suppliers that we utilize to purchase natural gas
on a monthly basis. Finally, from time to time, we raise funds
from the public debt and equity capital markets to fund our
liquidity needs.
We believe the liquidity provided by our senior notes and
committed credit facilities, combined with our operating cash
flows, will be sufficient to fund our working capital needs and
capital expenditure program for the remainder of fiscal 2010.
54
Cash
Flows
Our internally generated funds may change in the future due to a
number of factors, some of which we cannot control. These
include regulatory changes, prices for our products and
services, demand for such products and services, margin
requirements resulting from significant changes in commodity
prices, operational risks and other factors.
Cash flows from operating, investing and financing activities
for the six months ended March 31, 2010 and 2009 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Total cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
483,458
|
|
|
$
|
614,622
|
|
|
$
|
(131,164
|
)
|
Investing activities
|
|
|
(233,575
|
)
|
|
|
(225,255
|
)
|
|
|
(8,320
|
)
|
Financing activities
|
|
|
(129,933
|
)
|
|
|
46,001
|
|
|
|
(175,934
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
119,950
|
|
|
|
435,368
|
|
|
|
(315,418
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
111,203
|
|
|
|
46,717
|
|
|
|
64,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
231,153
|
|
|
$
|
482,085
|
|
|
$
|
(250,932
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities
Period-over-period
changes in our operating cash flows are primarily attributable
to changes in net income and working capital changes,
particularly within our natural gas distribution segment
resulting from the price of natural gas and the timing of
customer collections, payments for natural gas purchases and
deferred gas cost recoveries.
For the six months ended March 31, 2010, we generated
operating cash flow of $483.5 million from operating
activities compared with $614.6 million for the six months
ended March 31, 2009, primarily due to the fluctuation in
gas costs. Gas costs, which reached historically high levels
during the 2008 injection season, declined sharply when the
economy slipped into the recession and have remained relatively
stable since that time. Operating cash flow for the fiscal 2010
period reflects the recovery of lower gas costs through
purchased gas recovery mechanisms and sales. This is in contrast
to the fiscal 2009 period, where operating cash flow was
favorably influenced by the recovery of high gas costs during a
period of falling prices.
Cash
flows from investing activities
In recent years, a substantial portion of our cash resources has
been used to fund growth projects, our ongoing construction
program and improvements to information technology systems. Our
ongoing construction program enables us to provide natural gas
distribution services to our existing customer base, expand our
natural gas distribution services into new markets, enhance the
integrity of our pipelines and, more recently, expand our
intrastate pipeline network. In executing our current rate
strategy, we are directing discretionary capital spending to
jurisdictions that permit us to earn a timely return on our
investment. Currently, rate designs in our Mid-Tex, Louisiana,
Mississippi and West Texas natural gas distribution divisions
and our Atmos Pipeline Texas Division provide the
opportunity to include in their rate base approved capital costs
on a periodic basis without being required to file a rate case.
Capital expenditures for fiscal 2010 are expected to range from
$520 million to $535 million. For the six months ended
March 31, 2010, capital expenditures were
$232.6 million compared with $221.3 million for the
six months ended March 31, 2009. The $11.3 million
increase in capital expenditures primarily reflects spending for
the relocation of our information technology data center to a
new facility.
55
Cash
flows from financing activities
For the six months ended March 31, 2010, our financing
activities used $129.9 million of cash compared with a cash
inflow of $46.0 million in the prior-year period, primarily
due to the following:
|
|
|
|
|
$446.2 million decrease in cash inflows due to the absence
of proceeds from the issuance of long-term debt that occurred in
the prior-year period.
|
|
|
|
$3.8 million decrease due to a substantial decrease in the
number of shares of common stock issued to provide shares for
our Retirement Savings Plan due to a change to purchasing such
shares on the open market.
|
|
|
|
$2.1 million additional cash used due to an increase in
dividends paid in the current year compared to the prior year.
|
|
|
|
$1.9 million decrease in cash inflows due to the absence of
the settlement of a Treasury lock agreement that occurred in the
prior-year period.
|
These decreases in financing cash flows were partially offset by
a $277.6 million increase due to lower short-term debt
repayments. In the current-year period, $75.9 million of
short-term debt was repaid, compared with $353.5 million in
the prior-year period. The reduction in net borrowings reflects
the timing of the use of our line of credit to finance natural
gas purchases and working capital.
The following table summarizes our share issuances for the six
months ended March 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
Direct Stock Purchase Plan
|
|
|
103,529
|
|
|
|
220,361
|
|
Retirement Savings Plan and Trust
|
|
|
79,722
|
|
|
|
330,990
|
|
1998 Long-Term Incentive Plan
|
|
|
409,535
|
|
|
|
579,990
|
|
Outside Directors
Stock-for-Fee
Plan
|
|
|
2,040
|
|
|
|
1,590
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
594,826
|
|
|
|
1,132,931
|
|
|
|
|
|
|
|
|
|
|
The
year-over-year
decrease in the number of shares issued primarily reflects the
fact that we have started using shares purchased in the open
market rather than issuing shares for the Direct Stock Purchase
Plan and the Retirement Savings Plan. In addition, we awarded
fewer shares under our 1998 Long-Term Incentive Plan due to the
Company achieving a lower level of performance relative to the
target performance established under the Plan during fiscal 2009
compared to fiscal 2008. Further, a higher average stock price
during the second quarter of fiscal 2010 compared to the second
quarter of 2009 caused us to issue fewer shares during the
quarter.
Credit
Facilities
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply to meet our customers needs could significantly
affect our borrowing requirements. However, our short-term
borrowings reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide approximately $1.2 billion of working
capital funding. As of March 31, 2010, the amount available
to us under our credit facilities, net of outstanding letters of
credit, was approximately $1.1 billion. These facilities
are described in further detail in Note 5 to the unaudited
condensed consolidated financial statements.
56
Shelf
Registration
On March 31, 2010, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $1.3 billion in common stock
and/or
debt
securities available for issuance.
We had already received approvals from all requisite state
regulatory commissions to issue a total of $1.3 billion in
common stock
and/or
debt
securities under the new shelf registration statement, including
the carryforward of the $450 million of securities
remaining available for issuance under our shelf registration
statement filed with the SEC on March 23, 2009. Due to
certain restrictions imposed by one state regulatory commission
on our ability to issue securities under the new registration
statement, we will be able to issue a total of $950 million
in debt securities and $350 million in equity securities.
Credit
Ratings
Our credit ratings directly affect our ability to obtain
short-term and long-term financing in addition to the cost of
such financing. In determining our credit ratings, the rating
agencies consider a number of quantitative factors, including
debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and
pension liabilities and funding status. In addition, the rating
agencies consider qualitative factors such as consistency of our
earnings over time, the quality of our management and business
strategy, the risks associated with our regulated and
nonregulated businesses and the regulatory structures that
govern our rates in the states where we operate.
Our debt is rated by three rating agencies: Standard &
Poors Corporation (S&P), Moodys Investors
Service (Moodys) and Fitch Ratings, Ltd. (Fitch). In March
2010, Moodys upgraded our rating outlook from stable to
positive and affirmed the credit rating on our senior long-term
debt at Baa2 and on our commercial paper at
P-2.
Moodys stated that the key driver for the upgrade was
successful rate case outcomes over the past year. In March 2010,
S&P affirmed our senior long-term debt credit rating of
BBB+ and our rating outlook as stable. Fitch still maintains a
stable outlook. Our current debt ratings are all considered
investment grade and are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
Moodys
|
|
Fitch
|
|
Unsecured senior long-term debt
|
|
|
BBB+
|
|
|
|
Baa2
|
|
|
|
BBB+
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-2
|
|
|
|
F-2
|
|
A significant degradation in our operating performance or a
significant reduction in our liquidity caused by more limited
access to the private and public credit markets as a result of
deteriorating global financial and credit conditions could
trigger a negative change in our ratings outlook or even a
reduction in our credit ratings by the three credit rating
agencies. This would mean more limited access to the private and
public credit markets and an increase in the costs of such
borrowings.
A credit rating is not a recommendation to buy, sell or hold
securities. The highest investment grade credit rating for is
AAA for S&P, Aaa for Moodys and AAA for Fitch. The
lowest investment grade credit rating is BBB- for S&P, Baa3
for Moodys and BBB- for Fitch. Our credit ratings may be
revised or withdrawn at any time by the rating agencies, and
each rating should be evaluated independently of any other
rating. There can be no assurance that a rating will remain in
effect for any given period of time or that a rating will not be
lowered, or withdrawn entirely, by a rating agency if, in its
judgment, circumstances so warrant.
Debt
Covenants
We were in compliance with all of our debt covenants as of
March 31, 2010. Our debt covenants are described in greater
detail in Note 5 to the unaudited condensed consolidated
financial statements.
57
Capitalization
The following table presents our capitalization inclusive of
short-term debt and the current portion of long-term debt as of
March 31, 2010, September 30, 2009 and March 31,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
September 30, 2009
|
|
|
March 31, 2009
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
|
|
|
|
|
|
|
$
|
72,550
|
|
|
|
1.6
|
%
|
|
$
|
|
|
|
|
|
|
Long-term debt
|
|
|
2,169,606
|
|
|
|
48.1
|
%
|
|
|
2,169,531
|
|
|
|
49.1
|
%
|
|
|
2,569,366
|
|
|
|
54.1
|
%
|
Shareholders equity
|
|
|
2,338,843
|
|
|
|
51.9
|
%
|
|
|
2,176,761
|
|
|
|
49.3
|
%
|
|
|
2,178,494
|
|
|
|
45.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,508,449
|
|
|
|
100.0
|
%
|
|
$
|
4,418,842
|
|
|
|
100.0
|
%
|
|
$
|
4,747,860
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt as a percentage of total capitalization, including
short-term debt, was 48.1 percent at March 31, 2010,
50.7 percent at September 30, 2009 and
54.1 percent at March 31, 2009. Our ratio of total
debt to capitalization is typically greater during the winter
heating season as we incur short-term debt to fund natural gas
purchases and meet our working capital requirements. We intend
to maintain our debt to capitalization ratio in a target range
of 50 to 55 percent.
Contractual
Obligations and Commercial Commitments
Significant commercial commitments are described in Note 8
to the unaudited condensed consolidated financial statements.
There were no significant changes in our contractual obligations
and commercial commitments during the six months ended
March 31, 2010.
As we previously discussed in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009, in February
2008, Atmos Pipeline and Storage, LLC, a subsidiary of AEH,
announced plans to construct and operate a salt-cavern storage
project in Franklin Parish, Louisiana. In March 2010, we entered
into an option and acquisition agreement with a third party,
which provides the third party with the exclusive option to
develop the proposed Fort Necessity salt-dome natural gas
storage project. If the option is exercised, we will retain a
non-controlling equity position in Fort Necessity and will
share in a percentage of the profits.
Risk
Management Activities
We conduct risk management activities through our natural gas
distribution, natural gas marketing and pipeline, storage and
other segments. In our natural gas distribution segment, we use
a combination of physical storage, fixed physical contracts and
fixed financial contracts to reduce our exposure to unusually
large winter-period gas price increases.
In our natural gas marketing and pipeline, storage and other
segments, we manage our exposure to the risk of natural gas
price changes and lock in our gross profit margin through a
combination of storage and financial instruments, including
futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. To the extent our inventory cost and actual
sales and actual purchases do not correlate with the changes in
the market indices we use in our hedges, we could experience
ineffectiveness or the hedges may no longer meet the accounting
requirements for hedge accounting, resulting in the financial
instruments being treated as mark to market instruments through
earnings.
58
The following table shows the components of the change in fair
value of our natural gas distribution segments financial
instruments for the three and six months ended March 31,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(17,470
|
)
|
|
$
|
(51,314
|
)
|
|
$
|
(14,166
|
)
|
|
$
|
(63,677
|
)
|
Contracts realized/settled
|
|
|
(13,390
|
)
|
|
|
(47,231
|
)
|
|
|
(34,418
|
)
|
|
|
(100,996
|
)
|
Fair value of new contracts
|
|
|
(1,288
|
)
|
|
|
277
|
|
|
|
(2,236
|
)
|
|
|
(4,006
|
)
|
Other changes in value
|
|
|
10,413
|
|
|
|
76,405
|
|
|
|
29,085
|
|
|
|
146,816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
$
|
(21,735
|
)
|
|
$
|
(21,863
|
)
|
|
$
|
(21,735
|
)
|
|
$
|
(21,863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of our natural gas distribution segments
financial instruments at March 31, 2010 is presented below
by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at March 31, 2010
|
|
|
|
Maturity in Years
|
|
|
|
|
|
|
Less
|
|
|
|
|
|
|
|
|
Greater
|
|
|
Total Fair
|
|
Source of Fair Value
|
|
than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
than 5
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Prices actively quoted
|
|
$
|
(21,735
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(21,735
|
)
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(21,735
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(21,735
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows the components of the change in fair
value of our natural gas marketing segments financial
instruments for the three and six months ended March 31,
2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
32,306
|
|
|
$
|
(28,598
|
)
|
|
$
|
26,698
|
|
|
$
|
16,542
|
|
Contracts realized/settled
|
|
|
(22,030
|
)
|
|
|
6,972
|
|
|
|
(24,242
|
)
|
|
|
(13,275
|
)
|
Fair value of new contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other changes in value
|
|
|
3,951
|
|
|
|
(11,020
|
)
|
|
|
11,771
|
|
|
|
(35,913
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
|
14,227
|
|
|
|
(32,646
|
)
|
|
|
14,227
|
|
|
|
(32,646
|
)
|
Netting of cash collateral
|
|
|
7,199
|
|
|
|
79,098
|
|
|
|
7,199
|
|
|
|
79,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash collateral and fair value of contracts at period end
|
|
$
|
21,426
|
|
|
$
|
46,452
|
|
|
$
|
21,426
|
|
|
$
|
46,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of our natural gas marketing segments
financial instruments at March 31, 2010 is presented below
by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at March 31, 2010
|
|
|
|
Maturity in Years
|
|
|
|
|
|
|
Less
|
|
|
|
|
|
|
|
|
Greater
|
|
|
Total Fair
|
|
Source of Fair Value
|
|
than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
than 5
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Prices actively quoted
|
|
$
|
9,168
|
|
|
$
|
5,746
|
|
|
$
|
(687
|
)
|
|
$
|
|
|
|
$
|
14,227
|
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
9,168
|
|
|
$
|
5,746
|
|
|
$
|
(687
|
)
|
|
$
|
|
|
|
$
|
14,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
Pension
and Postretirement Benefits Obligations
For the six months ended March 31, 2010 and 2009, our total
net periodic pension and other benefits cost was
$25.4 million and $24.1 million. Those costs relating
to our natural gas distribution operations are recoverable
through our gas distribution rates; however, a portion of these
costs is capitalized into our distribution rate base. The
remaining costs are recorded as a component of operation and
maintenance expense.
Our fiscal 2010 costs were determined using a September 30,
2009 measurement date. As of September 30, 2009, interest
and corporate bond rates utilized to determine our discount
rates, were significantly higher than the interest and corporate
bond rates as of September 30, 2008, the measurement date
for our fiscal 2009 net periodic cost. Accordingly, we
decreased our discount rate used to determine our fiscal 2010
pension and benefit costs to 5.52 percent. We maintained
the expected return on our pension plan assets at
8.25 percent, despite the recent decline in the financial
markets as we believe this rate reflects the average rate of
expected earnings on plan assets that will fund our projected
benefit obligation. Although the fair value of our plan assets
has declined as the financial markets have declined, the impact
of this decline is mitigated by the fact that fluctuations in
asset values are smoothed for purposes of
determining net periodic pension cost. Accordingly, asset gains
and losses are recognized over time as a component of net
periodic pension and benefit costs for our Pension Account Plan,
our largest funded plan. Accordingly, our fiscal 2010 pension
and postretirement medical costs were materially the same as in
fiscal 2009.
In accordance with the Pension Protection Act of 2006 (PPA), we
determined the funded status of our plans as of January 1,
2010. Based upon this valuation, we expect we will be required
to contribute less than $5 million to our pension plans by
September 15, 2010. The need for this funding reflects the
decline in the fair value of the plans assets resulting
from the unfavorable market conditions experienced during 2008
and 2009. This contribution will increase the level of our plan
assets to achieve a desirable PPA funding threshold. With
respect to our postretirement medical plans, we anticipate
contributing a total of approximately $12 million to these
plans during fiscal 2010.
The projected pension liability, future funding requirements and
the amount of pension expense or income recognized for the plan
are subject to change, depending upon the actuarial value of
plan assets and the determination of future benefit obligations
as of each subsequent actuarial calculation date. These amounts
will be determined by actual investment returns, changes in
interest rates, values of assets in the plan and changes in the
demographic composition of the participants in the plan.
60
OPERATING
STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for
our natural gas distribution, regulated transmission and
storage, natural gas marketing and pipeline, storage and other
segments for the three and six month periods ended
March 31, 2010 and 2009.
Natural
Gas Distribution Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
METERS IN SERVICE, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,937,163
|
|
|
|
2,937,865
|
|
|
|
2,937,163
|
|
|
|
2,937,865
|
|
Commercial
|
|
|
272,925
|
|
|
|
274,449
|
|
|
|
272,925
|
|
|
|
274,449
|
|
Industrial
|
|
|
2,496
|
|
|
|
2,212
|
|
|
|
2,496
|
|
|
|
2,212
|
|
Public authority and other
|
|
|
9,461
|
|
|
|
9,243
|
|
|
|
9,461
|
|
|
|
9,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,222,045
|
|
|
|
3,223,769
|
|
|
|
3,222,045
|
|
|
|
3,223,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
24.4
|
|
|
|
31.9
|
|
|
|
24.4
|
|
|
|
31.9
|
|
SALES VOLUMES
MMcf
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
100,858
|
|
|
|
74,467
|
|
|
|
161,404
|
|
|
|
128,675
|
|
Commercial
|
|
|
46,615
|
|
|
|
36,689
|
|
|
|
77,105
|
|
|
|
65,018
|
|
Industrial
|
|
|
6,660
|
|
|
|
5,758
|
|
|
|
11,979
|
|
|
|
11,158
|
|
Public authority and other
|
|
|
4,397
|
|
|
|
4,646
|
|
|
|
7,356
|
|
|
|
8,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
158,530
|
|
|
|
121,560
|
|
|
|
257,844
|
|
|
|
213,006
|
|
Transportation volumes
|
|
|
40,545
|
|
|
|
36,169
|
|
|
|
76,786
|
|
|
|
71,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
199,075
|
|
|
|
157,729
|
|
|
|
334,630
|
|
|
|
284,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES
(000s)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
897,249
|
|
|
$
|
785,456
|
|
|
$
|
1,405,160
|
|
|
$
|
1,432,556
|
|
Commercial
|
|
|
366,260
|
|
|
|
334,815
|
|
|
|
585,680
|
|
|
|
637,509
|
|
Industrial
|
|
|
41,777
|
|
|
|
46,259
|
|
|
|
72,810
|
|
|
|
96,414
|
|
Public authority and other
|
|
|
32,386
|
|
|
|
36,991
|
|
|
|
52,584
|
|
|
|
68,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
1,337,672
|
|
|
|
1,203,521
|
|
|
|
2,116,234
|
|
|
|
2,234,864
|
|
Transportation revenues
|
|
|
18,219
|
|
|
|
16,889
|
|
|
|
34,694
|
|
|
|
32,655
|
|
Other gas revenues
|
|
|
10,097
|
|
|
|
10,010
|
|
|
|
17,954
|
|
|
|
18,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
1,365,988
|
|
|
$
|
1,230,420
|
|
|
$
|
2,168,882
|
|
|
$
|
2,286,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average transportation revenue per Mcf
|
|
$
|
0.45
|
|
|
$
|
0.47
|
|
|
$
|
0.45
|
|
|
$
|
0.46
|
|
Average cost of gas per Mcf sold
|
|
$
|
6.19
|
|
|
$
|
7.10
|
|
|
$
|
5.77
|
|
|
$
|
7.61
|
|
See footnote following these tables.
61
Regulated
Transmission and Storage, Natural Gas Marketing and Pipeline,
Storage and Other Operations Sales and Statistical
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
CUSTOMERS, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
727
|
|
|
|
698
|
|
|
|
727
|
|
|
|
698
|
|
Municipal
|
|
|
62
|
|
|
|
61
|
|
|
|
62
|
|
|
|
61
|
|
Other
|
|
|
498
|
|
|
|
527
|
|
|
|
498
|
|
|
|
527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,287
|
|
|
|
1,286
|
|
|
|
1,287
|
|
|
|
1,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing
|
|
|
20.1
|
|
|
|
20.4
|
|
|
|
20.1
|
|
|
|
20.4
|
|
Pipeline, storage and other
|
|
|
1.2
|
|
|
|
2.0
|
|
|
|
1.2
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.3
|
|
|
|
22.4
|
|
|
|
21.3
|
|
|
|
22.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REGULATED TRANSMISSION AND STORAGE VOLUMES
MMcf
(1)
|
|
|
192,441
|
|
|
|
193,356
|
|
|
|
350,214
|
|
|
|
385,528
|
|
NATURAL GAS MARKETING SALES VOLUMES
MMcf
(1)
|
|
|
123,877
|
|
|
|
123,066
|
|
|
|
226,138
|
|
|
|
233,724
|
|
OPERATING REVENUES
(000s)
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated transmission and storage
|
|
$
|
55,181
|
|
|
$
|
59,234
|
|
|
$
|
102,041
|
|
|
$
|
113,916
|
|
Natural gas marketing
|
|
|
692,152
|
|
|
|
708,658
|
|
|
|
1,236,423
|
|
|
|
1,496,153
|
|
Pipeline, storage and other
|
|
|
9,050
|
|
|
|
12,272
|
|
|
|
20,673
|
|
|
|
28,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
756,383
|
|
|
$
|
780,164
|
|
|
$
|
1,359,137
|
|
|
$
|
1,638,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note to preceding tables:
|
|
|
(1)
|
|
Sales volumes and revenues reflect segment operations, including
intercompany sales and transportation amounts.
|
RECENT
ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial
position, results of operations and cash flows are described in
Note 2 to the unaudited condensed consolidated financial
statements.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Information regarding our quantitative and qualitative
disclosures about market risk are disclosed in Item 7A in
our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. During the
six months ended March 31, 2010, there were no material
changes in our quantitative and qualitative disclosures about
market risk.
|
|
Item 4.
|
Controls
and Procedures
|
Managements
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the
participation of our management, including our principal
executive officer and principal financial officer, of the
effectiveness of the Companys disclosure controls and
procedures, as such term is defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934, as amended (Exchange
Act). Based on this evaluation, the Companys principal
executive officer and principal financial officer have concluded
that the Companys disclosure controls and procedures were
effective as of March 31, 2010 to provide reasonable
assurance that information required to be disclosed by us,
including our consolidated entities, in the reports that we file
or submit under the Exchange Act is recorded, processed,
summarized, and reported within the time periods specified by
the SECs rules and forms, including a reasonable level of
assurance that such information is accumulated and communicated
to our management, including our principal executive and
principal financial officers, as appropriate to allow timely
decisions regarding required disclosure.
62
Changes
in Internal Control over Financial Reporting
We did not make any changes in our internal control over
financial reporting (as defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act) during the second quarter of the fiscal
year ended September 30, 2010 that have materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
During the six months ended March 31, 2010, except as noted
in Note 8 to the unaudited condensed consolidated financial
statements, there were no material changes in the status of the
litigation and other matters that were disclosed in Note 12
to our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2009. We continue
to believe that the final outcome of such litigation and other
matters or claims will not have a material adverse effect on our
financial condition, results of operations or cash flows.
|
|
Item 5.
|
Other
Information
|
At the Annual Meeting of Shareholders of Atmos Energy
Corporation on February 3, 2010, 81,757,639 votes were cast
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Votes
|
|
|
|
|
|
|
|
|
|
Votes
|
|
|
Withheld/
|
|
|
Votes
|
|
|
Broker
|
|
|
|
For
|
|
|
Against
|
|
|
Abstaining
|
|
|
Non-Votes
|
|
|
Class I Director:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kim R. Cocklin
|
|
|
64,574,447
|
|
|
|
1,217,145
|
|
|
|
|
|
|
|
15,966,047
|
|
Class III Directors:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert W. Best
|
|
|
63,891,229
|
|
|
|
1,900,363
|
|
|
|
|
|
|
|
15,966,047
|
|
Robert C. Grable
|
|
|
64,932,497
|
|
|
|
859,095
|
|
|
|
|
|
|
|
15,966,047
|
|
Phillip E. Nichol
|
|
|
64,102,746
|
|
|
|
1,688,846
|
|
|
|
|
|
|
|
15,966,047
|
|
Charles K. Vaughan
|
|
|
64,210,783
|
|
|
|
1,580,809
|
|
|
|
|
|
|
|
15,966,047
|
|
Proposal regarding declassification of the Board of Directors
|
|
|
79,072,204
|
|
|
|
1,757,120
|
|
|
|
928,315
|
|
|
|
|
|
Ratification of the Audit Committees engagement of
Ernst & Young LLP to serve as the Companys
registered independent public accounting firm for fiscal year
2010
|
|
|
80,853,517
|
|
|
|
734,364
|
|
|
|
169,758
|
|
|
|
|
|
Mr. Travis W. Bain II, a Class I director and
Mr. Thomas J. Garland, a Class III director, retired
on February 3, 2010 at the conclusion of the Annual Meeting
of Shareholders, in accordance with the Boards mandatory
retirement policy. The remaining directors will continue to
serve until the expiration of their terms. The term of the
Class I directors, Kim R. Cocklin, Richard W. Douglas,
Ruben E. Esquivel and Richard K. Gordon, will expire in 2011.
The term of the Class II directors, Richard W. Cardin,
Thomas C. Meredith, Nancy K. Quinn, Stephen R. Springer and
Richard Ware II, will expire in 2012. The term of the
Class III directors, Robert W. Best, Robert C. Grable,
Phillip E. Nichol and Charles K. Vaughan will expire in 2013. As
a result of the declassification of the Board, which was
approved by our shareholders, beginning with the 2011 Annual
Meeting of Shareholders, each director elected will serve a
one-year term.
A list of exhibits required by Item 601 of
Regulation S-K
and filed as part of this report is set forth in the
Exhibits Index, which immediately precedes such exhibits.
63
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Atmos Energy Corporation
(Registrant)
|
|
|
|
By:
|
/s/
Fred
E. Meisenheimer
|
Fred E. Meisenheimer
Senior Vice President, Chief Financial Officer
and Treasurer
(Duly authorized signatory)
Date: May 6, 2010
64
EXHIBITS INDEX
Item 6
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
3
|
.1
|
|
Restated Articles of Incorporation of Atmos Energy
Corporation Texas (As Amended Effective
February 3, 2010)
|
|
|
|
3
|
.2
|
|
Restated Articles of Incorporation of Atmos Energy
Corporation Virginia (As Amended Effective
February 3, 2010)
|
|
|
|
12
|
|
|
Computation of ratio of earnings to fixed charges
|
|
|
|
15
|
|
|
Letter regarding unaudited interim financial information
|
|
|
|
31
|
|
|
Rule 13a-14(a)/15d-14(a)
Certifications
|
|
|
|
32
|
|
|
Section 1350 Certifications*
|
|
|
|
|
|
*
|
|
These certifications, which were made pursuant to 18 U.S.C.
Section 1350 by the Companys Chief Executive Officer
and Chief Financial Officer, furnished as Exhibit 32 to
this Quarterly Report on
Form 10-Q,
will not be deemed to be filed with the Commission or
incorporated by reference into any filing by the Company under
the Securities Act of 1933 or the Securities Exchange Act of
1934, except to the extent that the Company specifically
incorporates such certifications by reference.
|
65