e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the
quarterly period ended December 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 corporate Web site, 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 þ
No o
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
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(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 February 3, 2011.
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Class
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Shares Outstanding
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No Par Value
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90,648,911
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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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GAAP
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Generally Accepted Accounting Principles
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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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LPSC
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Louisiana Public Service Commission
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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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MPSC
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Mississippi Public Service Commission
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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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PRP
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Pipeline Replacement Program
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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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December 31,
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September 30,
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2010
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2010
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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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6,638,718
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$
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6,542,318
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Less accumulated depreciation and amortization
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1,779,374
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1,749,243
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Net property, plant and equipment
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4,859,344
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4,793,075
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Current assets
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Cash and cash equivalents
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129,892
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131,952
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Accounts receivable, net
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564,934
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273,207
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Gas stored underground
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339,105
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319,038
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Other current assets
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229,324
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150,995
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Total current assets
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1,263,255
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875,192
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Goodwill and intangible assets
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739,991
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740,148
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Deferred charges and other assets
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359,033
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355,376
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$
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7,221,623
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$
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6,763,791
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CAPITALIZATION AND LIABILITIES
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Shareholders equity
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Common stock, no par value (stated at $.005 per share);
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200,000,000 shares authorized; issued and outstanding:
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December 31, 2010 90,638,491 shares
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September 30, 2010 90,164,103 shares
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$
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453
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$
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451
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Additional paid-in capital
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1,724,899
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1,714,364
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Retained earnings
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529,900
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486,905
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Accumulated other comprehensive income (loss)
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19,601
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(23,372
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)
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Shareholders equity
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2,274,853
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2,178,348
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Long-term debt
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1,807,319
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1,809,551
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Total capitalization
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4,082,172
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3,987,899
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Current liabilities
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Accounts payable and accrued liabilities
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510,085
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266,208
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Other current liabilities
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349,914
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413,640
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Short-term debt
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247,993
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126,100
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Current maturities of long-term debt
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352,434
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360,131
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Total current liabilities
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1,460,426
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1,166,079
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Deferred income taxes
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892,090
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829,128
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Regulatory cost of removal obligation
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354,871
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350,521
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Deferred credits and other liabilities
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432,064
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430,164
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$
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7,221,623
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$
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6,763,791
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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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December 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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Natural gas distribution segment
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$
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727,195
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$
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802,894
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Regulated transmission and storage segment
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49,007
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46,860
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Nonregulated segment
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475,640
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548,016
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Intersegment eliminations
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(94,847
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(104,918
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1,156,995
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1,292,852
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Purchased gas cost
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Natural gas distribution segment
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427,423
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508,267
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Regulated transmission and storage segment
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Nonregulated segment
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450,462
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478,241
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Intersegment eliminations
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(94,450
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(104,505
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783,435
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882,003
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Gross profit
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373,560
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410,849
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Operating expenses
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Operation and maintenance
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116,594
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123,862
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Depreciation and amortization
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56,161
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53,839
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Taxes, other than income
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40,696
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42,552
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Total operating expenses
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213,451
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220,253
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Operating income
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160,109
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190,596
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Miscellaneous expense
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(737
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(269
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Interest charges
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38,917
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38,708
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Income before income taxes
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120,455
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151,619
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Income tax expense
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46,458
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58,289
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Net income
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$
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73,997
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$
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93,330
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Basic net income per share
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$
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0.81
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$
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1.00
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Diluted net income per share
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$
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0.81
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$
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1.00
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Cash dividends per share
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$
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0.340
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$
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0.335
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Weighted average shares outstanding:
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Basic
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90,082
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92,152
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Diluted
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90,408
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92,509
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See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH
FLOWS
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Three Months Ended
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December 31
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2010
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2009
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(Unaudited)
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(In thousands)
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Cash Flows From Operating Activities
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Net income
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$
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73,997
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$
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93,330
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Adjustments to reconcile net income to net cash provided by
operating activities:
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Depreciation and amortization:
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Charged to depreciation and amortization
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56,161
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53,839
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Charged to other accounts
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46
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36
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Deferred income taxes
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43,423
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12,832
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Other
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4,712
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4,382
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Net assets / liabilities from risk management activities
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5,304
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(26,891
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Net change in operating assets and liabilities
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(137,819
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(42,372
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Net cash provided by operating activities
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45,824
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95,156
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Cash Flows From Investing Activities
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Capital expenditures
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(123,162
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(115,439
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Other, net
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(370
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(1,873
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Net cash used in investing activities
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(123,532
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(117,312
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Cash Flows From Financing Activities
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Net increase in short-term debt
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112,628
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111,335
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Repayment of long-term debt
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(10,000
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)
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Cash dividends paid
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(31,002
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(31,234
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Repurchase of equity awards
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(3,231
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Issuance of common stock
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7,253
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5,681
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Net cash provided by financing activities
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75,648
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85,782
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Net increase (decrease) in cash and cash equivalents
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(2,060
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63,626
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Cash and cash equivalents at beginning of period
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131,952
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111,203
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Cash and cash equivalents at end of period
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$
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129,892
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$
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174,829
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See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
(Unaudited)
December 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 three 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 regulated 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 through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc, (AEH). AEH is wholly owned by the Company
and based in Houston, Texas. Through AEH, we provide natural gas
management and transportation services to municipalities,
natural gas distribution companies, including certain divisions
of Atmos Energy and third parties. AEH also seeks to maximize,
through asset optimization activities, the economic value
associated with 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.
As discussed in Note 10, we operate the Company through the
following three segments:
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the natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations,
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the regulated transmission and storage segment, which
includes the regulated pipeline and storage operations of our
Atmos Pipeline Texas Division and
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the nonregulated segment, which includes our nonregulated
natural gas management, nonregulated natural gas transmission,
storage and other services.
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2.
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Unaudited
Interim Financial Information
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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, 2010. 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, 2010. Because of
seasonal and other factors, the results of operations for the
three-month period ended December 31, 2010 are not
indicative of our results of operations for the full 2011 fiscal
year, which ends September 30, 2011.
We have evaluated subsequent events from the December 31,
2010 balance sheet date through the date these financial
statements were filed with the Securities and Exchange
Commission (SEC). Except as discussed
5
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
in Note 8, no events have occurred subsequent to the
balance sheet date that would require recognition or disclosure
in the condensed consolidated financial statements.
Significant
accounting policies
Our accounting policies are described in Note 2 to the
consolidated financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2010. During the
three months ended December 31, 2010, two new accounting
standards became applicable to the Company pertaining to
goodwill impairment testing for reporting units with zero or
negative carrying amounts and disclosure of supplementary pro
forma information for business combinations. The adoption of
these standards did not have an impact on our financial
position, results of operations or cash flows. There were no
other significant changes to our accounting policies during the
quarter ended December 31, 2010.
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 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
December 31, 2010 and September 30, 2010 included the
following:
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December 31,
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|
|
September 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
206,165
|
|
|
$
|
209,564
|
|
Merger and integration costs, net
|
|
|
6,596
|
|
|
|
6,714
|
|
Deferred gas costs
|
|
|
48,205
|
|
|
|
22,701
|
|
Regulatory cost of removal asset
|
|
|
38,533
|
|
|
|
31,014
|
|
Environmental costs
|
|
|
704
|
|
|
|
805
|
|
Rate case costs
|
|
|
4,756
|
|
|
|
4,505
|
|
Deferred franchise fees
|
|
|
452
|
|
|
|
1,161
|
|
Other
|
|
|
2,643
|
|
|
|
1,046
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
308,054
|
|
|
$
|
277,510
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
8,424
|
|
|
$
|
43,333
|
|
Deferred franchise fees
|
|
|
2,812
|
|
|
|
|
|
Regulatory cost of removal obligation
|
|
|
388,391
|
|
|
|
381,474
|
|
Other
|
|
|
6,012
|
|
|
|
6,112
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
405,639
|
|
|
$
|
430,919
|
|
|
|
|
|
|
|
|
|
|
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Currently 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 applicable state
regulatory commissions.
Comprehensive
income
The following table presents the components of comprehensive
income, net of related tax, for the three-month periods ended
December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
73,997
|
|
|
$
|
93,330
|
|
Unrealized holding gains on investments, net of tax expense of
$455 and $390 for the three months ended December 31, 2010
and 2009
|
|
|
776
|
|
|
|
664
|
|
Amortization and unrealized gain on interest rate hedging
transactions, net of tax expense of $18,704 and $248 for the
three months ended December 31, 2010 and 2009
|
|
|
31,847
|
|
|
|
422
|
|
Net unrealized gains on commodity hedging transactions, net of
tax expense of $6,617 and $4,254 for the three months ended
December 31, 2010 and 2009
|
|
|
10,350
|
|
|
|
6,654
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
116,970
|
|
|
$
|
101,070
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss), net of tax, as of
December 31, 2010 and September 30, 2010 consisted of
the following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
Unrealized holding gains on investments
|
|
$
|
4,981
|
|
|
$
|
4,205
|
|
Treasury lock
agreements(1)
|
|
|
26,379
|
|
|
|
(5,468
|
)
|
Cash flow hedges
|
|
|
(11,759
|
)
|
|
|
(22,109
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
19,601
|
|
|
$
|
(23,372
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The increase primarily reflects the change in fair value of
certain Treasury lock agreements executed in September 2010. See
Note 3 for further information. |
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, 2010. During the
first quarter there were no changes in our objectives,
strategies and accounting for these financial instruments.
Currently, we utilize financial instruments in our natural gas
distribution and nonregulated segments. We currently do not
manage commodity price risk with financial instruments in our
regulated transmission and storage segment.
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our financial instruments do not contain any credit risk-related
or other contingent features that could cause payments to be
accelerated 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 effects
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
2010-2011
heating season, in the jurisdictions where we are permitted to
utilize financial instruments, we anticipate hedging
approximately 35 percent, or 31.5 Bcf of the 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 costs 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
In our nonregulated operations, we aggregate and purchase gas
supply, arrange transportation
and/or
storage logistics and ultimately deliver 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 our
nonregulated segment. Through asset optimization activities, we
seek to enhance our gross profit by maximizing 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 segment is
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 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
8
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 nonregulated operations associated
with deliveries under fixed-priced forward contracts to deliver
gas to customers. These financial instruments have maturity
dates ranging from one to 56 months. We use financial
instruments, designated as fair value hedges, to hedge our
natural gas inventory used in our asset optimization activities
in our nonregulated segment.
Also, in our nonregulated operations, 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 in order 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 December 31, 2010,
our nonregulated segment had net open positions (including
existing storage and related financial contracts) of
0.5 Bcf.
Interest
Rate Risk Management Activities
We periodically manage interest rate risk by entering into
Treasury lock agreements to fix the Treasury yield component of
the interest cost associated with anticipated financings.
We intend to refinance our $350 million unsecured
7.375% Senior Notes that will mature in May 2011 through
the issuance of
30-year
unsecured senior notes in June 2011. Additionally, we anticipate
issuing $250 million of
30-year
unsecured senior notes in November 2011 to fund our capital
expenditure program. In September 2010, we entered into five
Treasury lock agreements to fix the Treasury yield component of
the interest cost associated with the anticipated issuances of
these senior notes. We designated all of these Treasury locks as
cash flow hedges of an anticipated transaction.
In prior years, we entered 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 the settled Treasury locks extend through fiscal
2035. However, the majority of the remaining amounts associated
with the settled Treasury locks will be recognized by the end of
fiscal 2019.
9
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
As of December 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
December 31, 2010, we had net long/(short) commodity
contracts outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Hedge
|
|
Gas
|
|
|
|
|
Contract Type
|
|
Designation
|
|
Distribution
|
|
Nonregulated
|
|
|
|
|
|
|
Quantity (MMcf)
|
|
|
|
Commodity contracts
|
|
Fair Value
|
|
|
|
|
|
|
(21,100
|
)
|
|
|
|
|
|
|
Cash Flow
|
|
|
|
|
|
|
35,177
|
|
|
|
|
|
|
|
Not designated
|
|
|
17,171
|
|
|
|
38,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,171
|
|
|
|
52,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 December 31, 2010 and September 30, 2010. 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 $25.3 million and $24.9 million
of cash held on deposit as of December 31, 2010 and
September 30, 2010 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
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
Nonregulated
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
28,489
|
|
|
$
|
28,489
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
384
|
|
|
|
384
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(38,419
|
)
|
|
|
(38,419
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(7,841
|
)
|
|
|
(7,841
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
(17,387
|
)
|
|
|
(17,387
|
)
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
50,653
|
|
|
|
16,061
|
|
|
|
66,714
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
77
|
|
|
|
1,816
|
|
|
|
1,893
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(22,944
|
)
|
|
|
(10,330
|
)
|
|
|
(33,274
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(980
|
)
|
|
|
(841
|
)
|
|
|
(1,821
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
26,806
|
|
|
|
6,706
|
|
|
|
33,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
26,806
|
|
|
$
|
(10,681
|
)
|
|
$
|
16,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
Nonregulated
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
40,030
|
|
|
$
|
40,030
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
2,461
|
|
|
|
2,461
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(56,575
|
)
|
|
|
(56,575
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(9,222
|
)
|
|
|
(9,222
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
(23,306
|
)
|
|
|
(23,306
|
)
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
2,219
|
|
|
|
16,459
|
|
|
|
18,678
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
47
|
|
|
|
2,056
|
|
|
|
2,103
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(48,942
|
)
|
|
|
(7,178
|
)
|
|
|
(56,120
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(2,924
|
)
|
|
|
(405
|
)
|
|
|
(3,329
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(49,600
|
)
|
|
|
10,932
|
|
|
|
(38,668
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(49,600
|
)
|
|
$
|
(12,374
|
)
|
|
$
|
(61,974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 months ended
December 31, 2010 and 2009.
Hedge ineffectiveness for our nonregulated segment 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 December 31, 2010 and
2009 we recognized a gain arising from fair value and cash flow
hedge ineffectiveness of $13.5 million and
$45.3 million. Additional information regarding
ineffectiveness recognized in the income statement is included
in the tables below.
Fair
Value Hedges
The impact of our nonregulated commodity contracts designated as
fair value hedges and the related hedged item on our condensed
consolidated income statement for the three months ended
December 31, 2010 and 2009 is presented below.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
(1,723
|
)
|
|
$
|
(2,639
|
)
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
15,625
|
|
|
|
49,183
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
13,902
|
|
|
$
|
46,544
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
921
|
|
|
$
|
64
|
|
Timing ineffectiveness
|
|
|
12,981
|
|
|
|
46,480
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
13,902
|
|
|
$
|
46,544
|
|
|
|
|
|
|
|
|
|
|
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 months ended December 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 when the
underlying physical and financial transactions are settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2010
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Nonregulated
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
|
$
|
|
|
|
$
|
(14,253
|
)
|
|
$
|
(14,253
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(444
|
)
|
|
|
(444
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(14,697
|
)
|
|
|
(14,697
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(670
|
)
|
|
|
|
|
|
|
(670
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(670
|
)
|
|
$
|
(14,697
|
)
|
|
$
|
(15,367
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2009
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
Nonregulated
|
|
|
Consolidated
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
|
$
|
|
|
|
$
|
(23,117
|
)
|
|
$
|
(23,117
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(1,218
|
)
|
|
|
(1,218
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(24,335
|
)
|
|
|
(24,335
|
)
|
Loss on settled Treasury lock agreements reclassified from AOCI
into interest expense
|
|
|
(670
|
)
|
|
|
|
|
|
|
(670
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(670
|
)
|
|
$
|
(24,335
|
)
|
|
$
|
(25,005
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
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
months ended December 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
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
31,425
|
|
|
$
|
|
|
Forward commodity contracts
|
|
|
1,657
|
|
|
|
(7,447
|
)
|
Recognition of losses in earnings due to settlements:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
422
|
|
|
|
422
|
|
Forward commodity contracts
|
|
|
8,693
|
|
|
|
14,101
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income from hedging, net of
tax(1)
|
|
$
|
42,197
|
|
|
$
|
7,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 in earnings as they are
amortized, while deferred losses associated with commodity
contracts are recognized in 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 December 31,
2010. However, the table below does not include the expected
recognition in earnings of the Treasury lock agreements entered
into on September 30, 2010 as those instruments have not
yet settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Commodity
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Next twelve months
|
|
$
|
(1,687
|
)
|
|
$
|
(7,286
|
)
|
|
$
|
(8,973
|
)
|
Thereafter
|
|
|
(3,702
|
)
|
|
|
(4,473
|
)
|
|
|
(8,175
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
$
|
(5,389
|
)
|
|
$
|
(11,759
|
)
|
|
$
|
(17,148
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 months ended December 31, 2010 and
2009 was an increase in revenue of $4.2 million and
$15.3 million. Note that this does not reflect the expected
gains or losses arising from the underlying physical
transactions associated with these financial instruments.
Therefore, this is not indicative of the economic gross profit
we realized when the underlying physical and financial
transactions are settled.
As discussed above, financial instruments used in our natural
gas distribution segment are not designated as hedges. However,
there is no earnings impact on 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 costs are recovered through our rates and recognized
in revenue. Accordingly, the impact of these financial
instruments is excluded.
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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, 2010. During the
first quarter of fiscal 2011, there were no changes in these
methods.
Fair value measurements also apply to the valuation of our
pension and post-retirement plan assets. Current accounting
guidance requires employers to annually disclose information
about fair value measurements of the assets of a defined benefit
pension or other postretirement plan. The fair value of these
assets is presented in Note 8 to the financial statements
in our Annual Report on
Form 10-K
for the fiscal 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 December 31, 2010 and
September 30, 2010. As required under authoritative
accounting literature, assets 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
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level
2)(1)
|
|
|
(Level 3)
|
|
|
Collateral(2)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
50,730
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50,730
|
|
Nonregulated segment
|
|
|
10,006
|
|
|
|
36,745
|
|
|
|
|
|
|
|
(25,033
|
)
|
|
|
21,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
10,006
|
|
|
|
87,475
|
|
|
|
|
|
|
|
(25,033
|
)
|
|
|
72,448
|
|
Hedged portion of gas stored underground
|
|
|
84,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,734
|
|
Available-for-sale
securities
|
|
|
42,617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
137,357
|
|
|
$
|
87,475
|
|
|
$
|
|
|
|
$
|
(25,033
|
)
|
|
$
|
199,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
23,924
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
23,924
|
|
Nonregulated segment
|
|
|
26,667
|
|
|
|
30,765
|
|
|
|
|
|
|
|
(50,329
|
)
|
|
|
7,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
26,667
|
|
|
$
|
54,689
|
|
|
$
|
|
|
|
$
|
(50,329
|
)
|
|
$
|
31,027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Netting and
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Cash
|
|
|
September 30,
|
|
|
|
(Level 1)
|
|
|
(Level
2)(1)
|
|
|
(Level 3)
|
|
|
Collateral(3)
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
2,266
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,266
|
|
Nonregulated segment
|
|
|
18,544
|
|
|
|
42,462
|
|
|
|
|
|
|
|
(41,760
|
)
|
|
|
19,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
18,544
|
|
|
|
44,728
|
|
|
|
|
|
|
|
(41,760
|
)
|
|
|
21,512
|
|
Hedged portion of gas stored underground
|
|
|
57,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57,507
|
|
Available-for-sale
securities
|
|
|
41,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
117,517
|
|
|
$
|
44,728
|
|
|
$
|
|
|
|
$
|
(41,760
|
)
|
|
$
|
120,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
51,866
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
51,866
|
|
Nonregulated segment
|
|
|
41,430
|
|
|
|
31,950
|
|
|
|
|
|
|
|
(66,649
|
)
|
|
|
6,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
41,430
|
|
|
$
|
83,816
|
|
|
$
|
|
|
|
$
|
(66,649
|
)
|
|
$
|
58,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 the relevant
authoritative accounting literature. In addition, as of
December 31, 2010, we had $25.3 million of cash held
in margin accounts to collateralize certain financial
instruments. Of this amount, $8.3 million was used to
offset current risk management liabilities under master netting
arrangements and the remaining $17.0 million is classified
as current risk management assets. |
|
(3) |
|
This column reflects adjustments to our gross financial
instrument assets and liabilities to reflect netting permitted
under our master netting agreements and the relevant
authoritative accounting literature. In addition, as of
September 30, 2010 we had $24.9 million of cash held
in margin accounts to collateralize certain financial
instruments. Of this amount, $12.6 million was used to
offset current risk management liabilities under master netting
arrangements and the remaining $12.3 million is classified
as current risk management assets. |
15
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 December 31, 2010:
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
|
(In thousands)
|
|
Carrying Amount
|
|
$
|
2,162,696
|
|
Fair Value
|
|
$
|
2,359,916
|
|
Long-term
debt
Long-term debt at December 31, 2010 and September 30,
2010 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
|
(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
|
|
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
|
|
|
393
|
|
|
|
393
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,162,696
|
|
|
|
2,172,696
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(2,943
|
)
|
|
|
(3,014
|
)
|
Current maturities
|
|
|
(352,434
|
)
|
|
|
(360,131
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,807,319
|
|
|
$
|
1,809,551
|
|
|
|
|
|
|
|
|
|
|
As noted above, our Unsecured 7.375% Senior Notes will
mature in May 2011 and our Unsecured 10% Notes will mature
in December 2011; accordingly, these have 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.
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 $1.0 billion of working
capital funding. At December 31, 2010 and
September 30, 2010, there was $248.0 million and
$126.1 million outstanding under our commercial paper
program. As of December 31, 2010, our commercial paper had
maturities of less than one week with an interest rate of
0.33 percent. 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 15, 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 December 31, 2010, there
were no borrowings under this facility, but we had
$248.0 million of commercial paper outstanding, leaving
$318.7 million available.
The second facility is a $200 million unsecured
180-day
facility that expires in April 2011. The facility bears interest
at a base rate or at a LIBOR-based rate for the applicable
interest period, plus a spread ranging from 1.50 percent to
2.75 percent, based on the Companys credit ratings.
At December 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
December 31, 2010, there were no borrowings outstanding
under this facility.
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 December 31, 2010, our
total-debt-to-total-capitalization ratio, as defined, was
54 percent. In addition, both the interest margin over the
Eurodollar rate and the fee 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, our regulated
operations have a $200 million intercompany revolving
credit facility with 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 five year 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, 2011 for up to
$350 million. There was $117.6 million outstanding
under this facility at December 31, 2010.
Nonregulated
Operations
Atmos Energy Marketing, LLC (AEM), a wholly-owned subsidiary of
AEH maintains a third-party commercial revolving credit facility
primarily to issue letters of credit and, on a less frequent
basis, to borrow funds for gas purchases and other working
capital needs. On December 8, 2010, AEM and the
participating
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
banks amended and restated AEMs one-year $450 million
committed revolving credit facility, replacing it with a
$200 million three-year facility with an accordion feature
that could increase AEMs borrowing capacity to
$500 million.
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 loans; (c) an offshore rate (based on
LIBOR with a three-month interest period) as in effect from
time to time; or (d) the cost of funds rate
which is the cost of funds as reasonably determined by the
administrative agent. The offshore rate is a floating rate equal
to the higher of (a) an offshore rate based upon LIBOR for
the applicable interest period; or (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
1.875 percent to 2.25 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
$6 million to $30 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 December 31, 2010, there were no borrowings outstanding
under this credit facility. However, at December 31, 2010,
AEM letters of credit totaling $37.8 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 $112.2 million at December 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 December 31, 2010,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 1.25 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$20 million to $40 million. As defined in the
financial covenants, at December 31, 2010, AEMs net
working capital was $195.8 million and its tangible net
worth was $207.0 million.
Finally, AEH had a $200 million intercompany demand credit
facility with AEC, which bore 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. In October
2010, we received regulatory approval to increase this facility,
effective December 1, 2010 through December 31, 2011,
to $350 million with substantially the same terms. There
were no borrowings outstanding under this facility at
December 31, 2010.
Shelf
Registration
We have an effective shelf registration statement with the
Securities and Exchange Commission (SEC) that permits us to
issue a total of $1.3 billion in common stock
and/or debt
securities. The shelf registration statement has been approved
by all requisite state regulatory commissions. 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.
At December 31, 2010, no amounts have been drawn down
against the shelf registration statement.
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.
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
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
December 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.
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. 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. Basic and diluted earnings per share for the
three months ended December 31, 2010 and 2009 are
calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Basic Earnings Per Share
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
73,997
|
|
|
$
|
93,330
|
|
Less: Income allocated to participating securities
|
|
|
779
|
|
|
|
1,037
|
|
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
73,218
|
|
|
$
|
92,293
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
90,082
|
|
|
|
92,152
|
|
|
|
|
|
|
|
|
|
|
Net income per share Basic
|
|
$
|
0.81
|
|
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Share
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
73,218
|
|
|
$
|
92,293
|
|
Effect of dilutive stock options and other shares
|
|
|
2
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
Net income available to common shareholders
|
|
$
|
73,220
|
|
|
$
|
92,296
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average shares outstanding
|
|
|
90,082
|
|
|
|
92,152
|
|
Additional dilutive stock options and other shares
|
|
|
326
|
|
|
|
357
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average shares outstanding
|
|
|
90,408
|
|
|
|
92,509
|
|
|
|
|
|
|
|
|
|
|
Net income per share Diluted
|
|
$
|
0.81
|
|
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
19
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 months ended December 31, 2010 and
2009 as their exercise price was less than the average market
price of the common stock during that period.
|
|
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 months
ended December 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.
In August 2010, the Board of Directors of Atmos Energy approved
a proposal to close the Pension Account Plan (PAP) to new
participants, effective October 1, 2010. Employees
participating in the PAP as of October 1, 2010 were allowed
to make a one-time election to migrate from the PAP into our
defined contribution plan with enhanced features, effective
January 1, 2011. Participants who chose to remain in the
PAP will continue to earn benefits and interest allocations with
no changes to their existing benefits. During the first quarter
ended December 31, 2010, a limited number of participants
elected to join the new plan, which resulted in an immaterial
curtailment gain and a revaluation of the net periodic pension
cost for the remainder of fiscal 2011. The curtailment gain will
be recorded in our second fiscal quarter. The revaluation of the
net periodic pension cost resulted in an increase in the
discount rate, effective January 1, 2011 to
5.68 percent, which will reduce our net periodic pension
cost by approximately $1.8 million for the remainder of the
fiscal year. All other actuarial assumptions remained the same.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
4,380
|
|
|
$
|
3,993
|
|
|
$
|
3,601
|
|
|
$
|
3,360
|
|
Interest cost
|
|
|
6,924
|
|
|
|
6,524
|
|
|
|
3,203
|
|
|
|
3,018
|
|
Expected return on assets
|
|
|
(5,963
|
)
|
|
|
(6,320
|
)
|
|
|
(682
|
)
|
|
|
(615
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
378
|
|
|
|
378
|
|
Amortization of prior service cost
|
|
|
(112
|
)
|
|
|
(193
|
)
|
|
|
(362
|
)
|
|
|
(375
|
)
|
Amortization of actuarial loss
|
|
|
3,494
|
|
|
|
2,822
|
|
|
|
87
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
8,723
|
|
|
$
|
6,826
|
|
|
$
|
6,225
|
|
|
$
|
5,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three months ended December 31, 2010 and 2009 are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Discount rate
|
|
|
5.39
|
%
|
|
|
5.52
|
%
|
|
|
5.39
|
%
|
|
|
5.52
|
%
|
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
|
%
|
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
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2006 (PPA), we determined the funded status of our plans as of
January 1, 2011. Based upon this valuation, we expect we
will be required to contribute less than $2 million to our
pension plans by September 15, 2011.
We contributed $2.7 million to our other post-retirement
benefit plans during the three months ended December 31,
2010. We expect to contribute a total of approximately
$11 million to these plans during fiscal 2011.
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
|
|
|
|
|
|
|
Cost
|
|
|
Gain
|
|
|
Loss
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
As of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
28,686
|
|
|
$
|
6,598
|
|
|
$
|
|
|
|
$
|
35,284
|
|
Foreign equity mutual funds
|
|
|
4,426
|
|
|
|
1,308
|
|
|
|
|
|
|
|
5,734
|
|
Money market funds
|
|
|
1,599
|
|
|
|
|
|
|
|
|
|
|
|
1,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
34,711
|
|
|
$
|
7,906
|
|
|
$
|
|
|
|
$
|
42,617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
29,540
|
|
|
$
|
5,698
|
|
|
$
|
|
|
|
$
|
35,238
|
|
Foreign equity mutual funds
|
|
|
4,753
|
|
|
|
976
|
|
|
|
|
|
|
|
5,729
|
|
Money market funds
|
|
|
499
|
|
|
|
|
|
|
|
|
|
|
|
499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
34,792
|
|
|
$
|
6,674
|
|
|
$
|
|
|
|
$
|
41,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2010, except as
noted below, there were no material changes in the status of
such litigation and environmental-related matters or claims
during the three months ended December 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.
Since April 2009, Atmos Energy and two subsidiaries of AEH, AEM
and Atmos Gathering Company, LLC, have been involved in a
lawsuit filed in the Circuit Court of Edmonson County, Kentucky
related to our Park City Gathering Project. The dispute which
gave rise to the litigation involves the amount of royalties due
from a third party producer to landowners (who own the mineral
rights) for natural gas produced from the landowners
properties. The third party producer was operating pursuant to
leases between the landowners and certain investors/working
interest owners. The third party producer filed a petition in
bankruptcy, which was subsequently dismissed due to the lack of
meaningful assets to reorganize or liquidate.
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Although certain Atmos Energy companies entered into contracts
with the third party producer to gather, treat and ultimately
sell natural gas produced from the landowners properties,
no Atmos Energy company had a contractual relationship with the
landowners or the investors/working interest owners. After the
lawsuit was filed, the landowners were successful in terminating
for non-payment of royalties the leases related to the
production of natural gas from their properties. Subsequent to
termination, the investors/working interest owners under such
leases filed additional claims against us for the termination of
the leases.
During the trial, the landowners and the investors/working
interest owners requested an award of compensatory damages plus
punitive damages against us. On December 17, 2010, the jury
returned a verdict in favor of the landowners and
investor/working interest owners and awarded compensatory
damages of $3.8 million and punitive damages of
$27.5 million payable by Atmos Energy and the two AEH
subsidiaries.
A hearing is scheduled on February 28, 2011 to hear a
number of motions, including a motion to dismiss the jury
verdict and a motion for a new trial. In the event the trial
judge denies these motions, Atmos Energy will appeal the
decision. We strongly believe that the trial court erred in not
granting our motion to dismiss the lawsuit prior to trial and
that the verdict is unsupported by law. After consultation with
counsel, we believe that it is probable that any judgment based
on this verdict would be overturned on appeal.
We have accrued what we believe is an adequate amount for the
anticipated resolution of this matter; however, the amount
accrued does not reflect the amount of the verdict. The Company
does not have insurance coverage that could mitigate any losses
that may arise from the resolution of this matter; however, we
believe that the final outcome will not have a material adverse
effect on our financial condition, results of operations or cash
flows.
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 and response actions to such
environmental-related matters or claims cannot be predicted with
certainty, we believe the final outcome of such litigation and
response actions will not have a material adverse effect on our
financial condition, results of operations or cash flows.
Purchase
Commitments
AEH has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At December 31, 2010, AEH was committed to
purchase 74.1 Bcf within one year, 36.2 Bcf within one
to three years and 6.4 Bcf after three years under indexed
contracts. AEH is committed to purchase 3.1 Bcf within one
year and 0.2 Bcf within one to three years under fixed
price contracts with prices ranging from $3.87 to $6.36 per Mcf.
Purchases under these contracts totaled $334.2 million and
$354.1 million for the three months ended December 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.
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in this
service area which obligate it to purchase specified volumes at
market and fixed prices. The estimated commitments under these
contracts as of December 31, 2010 are as follows (in
thousands):
|
|
|
|
|
2011
|
|
$
|
178,340
|
|
2012
|
|
|
73,729
|
|
2013
|
|
|
5,353
|
|
2014
|
|
|
2,311
|
|
2015
|
|
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
259,733
|
|
|
|
|
|
|
Our nonregulated segment maintains 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, 2010. There were no
material changes to the estimated storage and transportation
fees for the quarter ended December 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, 2010, 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. There have been no material developments in this
matter during the quarter ended December 31, 2010. 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.
We have been replacing certain steel service lines in our
Mid-Tex Division since our acquisition of the natural gas
distribution system in 2004. Since early 2010, we have been
discussing the financial and operational details of an
accelerated steel service line replacement program with
representatives of 440 municipalities served by our Mid-Tex
Division. As previously discussed in Note 12 to the
consolidated financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2010, all of the
cities our Mid-Tex Division serves have agreed to a program of
installing 100,000 replacements during the next two years, with
approved recovery of the associated return, depreciation and
taxes. Under the terms of the agreement, the accelerated
replacement program commenced in the first quarter of fiscal
2011, replacing 8,079 lines for a cost of $10.0 million.
The program is progressing on schedule for completion in
September 2012.
In July 2010, the Dodd-Frank Act was enacted, representing an
extensive overhaul of the framework for regulation of
U.S. financial markets. The Dodd-Frank Act calls for
various regulatory agencies, including the SEC and the
Commodities Futures Trading Commission, to establish regulations
for implementation of many of the provisions of the Dodd-Frank
Act, which we expect will provide additional clarity regarding
the extent of the impact of this legislation on us. The costs of
participating in financial markets for hedging certain risks
inherent in our business may be increased as a result of the new
legislation. We may also incur additional costs associated with
compliance with new regulations and anticipate additional
reporting and disclosure obligations.
As of December 31, 2010, rate cases were in progress in our
Atmos Pipeline Texas and West Texas service areas
and annual rate filing mechanisms were in progress in our
Louisiana and Mississippi service
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
areas. In addition, there were other ratemaking activities in
progress in our Kansas and Missouri 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, 2010. During the
three months ended December 31, 2010, there were no
material changes in our concentration of credit risk.
Through November 30, 2010, our operations were divided into
four segments:
|
|
|
|
|
The natural gas distribution segment, which included our
regulated natural gas distribution and related sales operations.
|
|
|
|
The regulated transmission and storage segment, which
included the regulated pipeline and storage operations of our
Atmos Pipeline Texas Division.
|
|
|
|
The natural gas marketing segment, which included a
variety of nonregulated natural gas management services.
|
|
|
|
The pipeline, storage and other segment, which included
our nonregulated natural gas gathering transmission and storage
services.
|
As a result of the appointment of a new CEO effective
October 1, 2010, during the first quarter of fiscal 2011,
we revised the information used by the chief operating decision
maker to manage the Company. As a result of this change,
effective December 1, 2010, we began dividing our
operations into the following three segments:
|
|
|
|
|
The natural gas distribution segment, remains unchanged
and includes our regulated natural gas distribution and related
sales operations.
|
|
|
|
The regulated transmission and storage segment, remains
unchanged and includes the regulated pipeline and storage
operations of our Atmos Pipeline Texas Division.
|
|
|
|
The nonregulated segment, is comprised of our
nonregulated natural gas management, nonregulated natural gas
transmission, storage and other services which were previously
reported in the natural gas marketing and pipeline, storage and
other segments.
|
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in differing 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, 2010. We evaluate
performance based on net income or loss of the respective
operating units.
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income statements for the three month periods ended
December 31, 2010 and 2009 by segment are presented in the
following tables to reflect our business structure as of
December 31, 2010. Prior-year amounts have been restated
accordingly.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Nonregulated
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
726,994
|
|
|
$
|
21,233
|
|
|
$
|
408,768
|
|
|
$
|
|
|
|
$
|
1,156,995
|
|
Intersegment revenues
|
|
|
201
|
|
|
|
27,774
|
|
|
|
66,872
|
|
|
|
(94,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
727,195
|
|
|
|
49,007
|
|
|
|
475,640
|
|
|
|
(94,847
|
)
|
|
|
1,156,995
|
|
Purchased gas cost
|
|
|
427,423
|
|
|
|
|
|
|
|
450,462
|
|
|
|
(94,450
|
)
|
|
|
783,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
299,772
|
|
|
|
49,007
|
|
|
|
25,178
|
|
|
|
(397
|
)
|
|
|
373,560
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
91,333
|
|
|
|
15,574
|
|
|
|
10,084
|
|
|
|
(397
|
)
|
|
|
116,594
|
|
Depreciation and amortization
|
|
|
49,278
|
|
|
|
5,799
|
|
|
|
1,084
|
|
|
|
|
|
|
|
56,161
|
|
Taxes, other than income
|
|
|
34,976
|
|
|
|
3,553
|
|
|
|
2,167
|
|
|
|
|
|
|
|
40,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
175,587
|
|
|
|
24,926
|
|
|
|
13,335
|
|
|
|
(397
|
)
|
|
|
213,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
124,185
|
|
|
|
24,081
|
|
|
|
11,843
|
|
|
|
|
|
|
|
160,109
|
|
Miscellaneous income (expense)
|
|
|
(709
|
)
|
|
|
(282
|
)
|
|
|
290
|
|
|
|
(36
|
)
|
|
|
(737
|
)
|
Interest charges
|
|
|
29,719
|
|
|
|
8,064
|
|
|
|
1,170
|
|
|
|
(36
|
)
|
|
|
38,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
93,757
|
|
|
|
15,735
|
|
|
|
10,963
|
|
|
|
|
|
|
|
120,455
|
|
Income tax expense
|
|
|
36,439
|
|
|
|
5,633
|
|
|
|
4,386
|
|
|
|
|
|
|
|
46,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
57,318
|
|
|
$
|
10,102
|
|
|
$
|
6,577
|
|
|
$
|
|
|
|
$
|
73,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
109,499
|
|
|
$
|
12,739
|
|
|
$
|
924
|
|
|
$
|
|
|
|
$
|
123,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Nonregulated
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
802,686
|
|
|
$
|
19,842
|
|
|
$
|
470,324
|
|
|
$
|
|
|
|
$
|
1,292,852
|
|
Intersegment revenues
|
|
|
208
|
|
|
|
27,018
|
|
|
|
77,692
|
|
|
|
(104,918
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
802,894
|
|
|
|
46,860
|
|
|
|
548,016
|
|
|
|
(104,918
|
)
|
|
|
1,292,852
|
|
Purchased gas cost
|
|
|
508,267
|
|
|
|
|
|
|
|
478,241
|
|
|
|
(104,505
|
)
|
|
|
882,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
294,627
|
|
|
|
46,860
|
|
|
|
69,775
|
|
|
|
(413
|
)
|
|
|
410,849
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
96,033
|
|
|
|
17,579
|
|
|
|
10,663
|
|
|
|
(413
|
)
|
|
|
123,862
|
|
Depreciation and amortization
|
|
|
47,857
|
|
|
|
4,942
|
|
|
|
1,040
|
|
|
|
|
|
|
|
53,839
|
|
Taxes, other than income
|
|
|
37,990
|
|
|
|
3,267
|
|
|
|
1,295
|
|
|
|
|
|
|
|
42,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
181,880
|
|
|
|
25,788
|
|
|
|
12,998
|
|
|
|
(413
|
)
|
|
|
220,253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
112,747
|
|
|
|
21,072
|
|
|
|
56,777
|
|
|
|
|
|
|
|
190,596
|
|
Miscellaneous income (expense)
|
|
|
657
|
|
|
|
43
|
|
|
|
376
|
|
|
|
(1,345
|
)
|
|
|
(269
|
)
|
Interest charges
|
|
|
29,678
|
|
|
|
7,968
|
|
|
|
2,407
|
|
|
|
(1,345
|
)
|
|
|
38,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
83,726
|
|
|
|
13,147
|
|
|
|
54,746
|
|
|
|
|
|
|
|
151,619
|
|
Income tax expense
|
|
|
32,278
|
|
|
|
4,693
|
|
|
|
21,318
|
|
|
|
|
|
|
|
58,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
51,448
|
|
|
$
|
8,454
|
|
|
$
|
33,428
|
|
|
$
|
|
|
|
$
|
93,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
100,462
|
|
|
$
|
13,759
|
|
|
$
|
1,218
|
|
|
$
|
|
|
|
$
|
115,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at December 31, 2010 and
September 30, 2010 by segment is presented to reflect our
business structure as of December 31, 2010 in the following
tables. Prior-year amounts have been restated accordingly.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Nonregulated
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
4,020,501
|
|
|
$
|
753,679
|
|
|
$
|
85,164
|
|
|
$
|
|
|
|
$
|
4,859,344
|
|
Investment in subsidiaries
|
|
|
647,892
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
(645,796
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
36,144
|
|
|
|
|
|
|
|
93,748
|
|
|
|
|
|
|
|
129,892
|
|
Assets from risk management activities
|
|
|
50,653
|
|
|
|
|
|
|
|
21,718
|
|
|
|
|
|
|
|
72,371
|
|
Other current assets
|
|
|
774,001
|
|
|
|
11,908
|
|
|
|
418,599
|
|
|
|
(143,516
|
)
|
|
|
1,060,992
|
|
Intercompany receivables
|
|
|
520,489
|
|
|
|
|
|
|
|
|
|
|
|
(520,489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,381,287
|
|
|
|
11,908
|
|
|
|
534,065
|
|
|
|
(664,005
|
)
|
|
|
1,263,255
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
677
|
|
|
|
|
|
|
|
677
|
|
Goodwill
|
|
|
572,262
|
|
|
|
132,341
|
|
|
|
34,711
|
|
|
|
|
|
|
|
739,314
|
|
Noncurrent assets from risk management activities
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
|
|
Deferred charges and other assets
|
|
|
334,654
|
|
|
|
8,210
|
|
|
|
16,092
|
|
|
|
|
|
|
|
358,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,956,673
|
|
|
$
|
906,138
|
|
|
$
|
668,613
|
|
|
$
|
(1,309,801
|
)
|
|
$
|
7,221,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,274,853
|
|
|
$
|
222,788
|
|
|
$
|
425,104
|
|
|
$
|
(647,892
|
)
|
|
$
|
2,274,853
|
|
Long-term debt
|
|
|
1,807,057
|
|
|
|
|
|
|
|
262
|
|
|
|
|
|
|
|
1,807,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,081,910
|
|
|
|
222,788
|
|
|
|
425,366
|
|
|
|
(647,892
|
)
|
|
|
4,082,172
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
352,303
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
352,434
|
|
Short-term debt
|
|
|
365,614
|
|
|
|
|
|
|
|
|
|
|
|
(117,621
|
)
|
|
|
247,993
|
|
Liabilities from risk management activities
|
|
|
22,944
|
|
|
|
|
|
|
|
621
|
|
|
|
|
|
|
|
23,565
|
|
Other current liabilities
|
|
|
618,402
|
|
|
|
12,779
|
|
|
|
229,052
|
|
|
|
(23,799
|
)
|
|
|
836,434
|
|
Intercompany payables
|
|
|
|
|
|
|
516,442
|
|
|
|
4,047
|
|
|
|
(520,489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,359,263
|
|
|
|
529,221
|
|
|
|
233,851
|
|
|
|
(661,909
|
)
|
|
|
1,460,426
|
|
Deferred income taxes
|
|
|
740,068
|
|
|
|
149,100
|
|
|
|
2,922
|
|
|
|
|
|
|
|
892,090
|
|
Noncurrent liabilities from risk management activities
|
|
|
980
|
|
|
|
|
|
|
|
6,482
|
|
|
|
|
|
|
|
7,462
|
|
Regulatory cost of removal obligation
|
|
|
354,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354,871
|
|
Deferred credits and other liabilities
|
|
|
419,581
|
|
|
|
5,029
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
424,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,956,673
|
|
|
$
|
906,138
|
|
|
$
|
668,613
|
|
|
$
|
(1,309,801
|
)
|
|
$
|
7,221,623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Nonregulated
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,959,112
|
|
|
$
|
748,947
|
|
|
$
|
85,016
|
|
|
$
|
|
|
|
$
|
4,793,075
|
|
Investment in subsidiaries
|
|
|
620,863
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
(618,767
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
31,952
|
|
|
|
|
|
|
|
100,000
|
|
|
|
|
|
|
|
131,952
|
|
Assets from risk management activities
|
|
|
2,219
|
|
|
|
|
|
|
|
18,356
|
|
|
|
|
|
|
|
20,575
|
|
Other current assets
|
|
|
528,655
|
|
|
|
19,504
|
|
|
|
325,348
|
|
|
|
(150,842
|
)
|
|
|
722,665
|
|
Intercompany receivables
|
|
|
546,313
|
|
|
|
|
|
|
|
|
|
|
|
(546,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,109,139
|
|
|
|
19,504
|
|
|
|
443,704
|
|
|
|
(697,155
|
)
|
|
|
875,192
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
834
|
|
|
|
|
|
|
|
834
|
|
Goodwill
|
|
|
572,262
|
|
|
|
132,341
|
|
|
|
34,711
|
|
|
|
|
|
|
|
739,314
|
|
Noncurrent assets from risk management activities
|
|
|
47
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
937
|
|
Deferred charges and other assets
|
|
|
324,707
|
|
|
|
13,037
|
|
|
|
16,695
|
|
|
|
|
|
|
|
354,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,586,130
|
|
|
$
|
913,829
|
|
|
$
|
579,754
|
|
|
$
|
(1,315,922
|
)
|
|
$
|
6,763,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,178,348
|
|
|
$
|
212,687
|
|
|
$
|
408,176
|
|
|
$
|
(620,863
|
)
|
|
$
|
2,178,348
|
|
Long-term debt
|
|
|
1,809,289
|
|
|
|
|
|
|
|
262
|
|
|
|
|
|
|
|
1,809,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,987,637
|
|
|
|
212,687
|
|
|
|
408,438
|
|
|
|
(620,863
|
)
|
|
|
3,987,899
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
360,000
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
360,131
|
|
Short-term debt
|
|
|
258,488
|
|
|
|
|
|
|
|
|
|
|
|
(132,388
|
)
|
|
|
126,100
|
|
Liabilities from risk management activities
|
|
|
48,942
|
|
|
|
|
|
|
|
731
|
|
|
|
|
|
|
|
49,673
|
|
Other current liabilities
|
|
|
473,076
|
|
|
|
10,949
|
|
|
|
162,508
|
|
|
|
(16,358
|
)
|
|
|
630,175
|
|
Intercompany payables
|
|
|
|
|
|
|
543,007
|
|
|
|
3,306
|
|
|
|
(546,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,140,506
|
|
|
|
553,956
|
|
|
|
166,676
|
|
|
|
(695,059
|
)
|
|
|
1,166,079
|
|
Deferred income taxes
|
|
|
691,126
|
|
|
|
142,337
|
|
|
|
(4,335
|
)
|
|
|
|
|
|
|
829,128
|
|
Noncurrent liabilities from risk management activities
|
|
|
2,924
|
|
|
|
|
|
|
|
6,000
|
|
|
|
|
|
|
|
8,924
|
|
Regulatory cost of removal obligation
|
|
|
350,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
350,521
|
|
Deferred credits and other liabilities
|
|
|
413,416
|
|
|
|
4,849
|
|
|
|
2,975
|
|
|
|
|
|
|
|
421,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,586,130
|
|
|
$
|
913,829
|
|
|
$
|
579,754
|
|
|
$
|
(1,315,922
|
)
|
|
$
|
6,763,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
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 December 31, 2010, the
related condensed consolidated statements of income for the
three-month periods ended December 31, 2010 and 2009, and
the condensed consolidated statements of cash flows for the
three-month periods ended December 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, 2010, 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 12, 2010, 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, 2010, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Dallas, Texas
February 9, 2011
29
|
|
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, 2010.
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 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 along with increased costs of
health care benefits; 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; possible increased federal, state and
local regulation of the safety of our operations; 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 its 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 three 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 provide natural gas
management and transportation services to municipalities,
natural gas distribution companies including certain of our
natural gas distribution divisions and third parties primarily
in the Midwest and Southeast. Through our asset optimization
activities, we also seek to maximize the economic value
associated with the storage and transportation capacity we own
or control.
30
As discussed in Note 10, as a result of the appointment of
a new CEO effective October 1, 2010, during the first
quarter of fiscal 2011, we revised the information used by the
chief operating decision maker to manage the Company. As a
result of this change, effective December 1, 2010, we began
dividing our operations into the following three 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 and
|
|
|
|
the nonregulated segment, which includes our nonregulated
natural gas management, nonregulated natural gas transmission,
storage and other 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, 2010 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 three months ended
December 31, 2010.
RESULTS
OF OPERATIONS
We reported net income of $74.0 million, or $0.81 per
diluted share for the three months ended December 31, 2010
compared with net income of $93.3 million, or $1.00 per
diluted share in the prior-year quarter. Regulated operations
contributed 91 percent of our net income during this period
with our nonregulated operations contributing the remaining nine
percent. Excluding the impact of unrealized margins, diluted
earnings per share increased $0.10 compared with the prior-year
quarter. The $0.10 per diluted share improvement reflects
increased gross profit in our regulated operations from
ratemaking activities, a 4 percent increase in regulated
transmission and storage volumes and an 8 percent increase
in nonregulated delivered gas volumes. These increases were
partially offset by a 10 percent decline in natural gas
distribution volumes and the continued adverse impact of low
natural gas price volatility, which contributed to a decline in
nonregulated
per-unit
delivered gas margins and realized asset optimization margins.
31
During the quarter, we executed on our strategy to streamline
our credit facilities. In October 2010, we replaced our
$200 million
364-day
revolving credit agreement prior to its expiration with a
$200 million
180-day
revolving credit agreement. Additionally, in December 2010, we
replaced Atmos Energy Marketings (AEM) $450 million
364-day
revolving credit facility with a $200 million three-year
facility with an accordion feature that could increase
AEMs borrowing capacity to $500 million. The new
credit facilities should continue to help ensure we have
sufficient liquidity to fund our working capital needs while
reducing our financing costs.
The following table presents our consolidated financial
highlights for the three months ended December 31, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
December 31
|
|
|
2010
|
|
2009
|
|
|
(In thousands, except per share data)
|
|
Operating revenues
|
|
$
|
1,156,995
|
|
|
$
|
1,292,852
|
|
Gross profit
|
|
|
373,560
|
|
|
|
410,849
|
|
Operating expenses
|
|
|
213,451
|
|
|
|
220,253
|
|
Operating income
|
|
|
160,109
|
|
|
|
190,596
|
|
Miscellaneous expense
|
|
|
(737
|
)
|
|
|
(269
|
)
|
Interest charges
|
|
|
38,917
|
|
|
|
38,708
|
|
Income before income taxes
|
|
|
120,455
|
|
|
|
151,619
|
|
Income tax expense
|
|
|
46,458
|
|
|
|
58,289
|
|
Net income
|
|
$
|
73,997
|
|
|
$
|
93,330
|
|
Diluted net income per share
|
|
$
|
0.81
|
|
|
$
|
1.00
|
|
Our consolidated net income during the three months ended
December 31, 2010 and 2009 was earned in each of our
business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
57,318
|
|
|
$
|
51,448
|
|
|
$
|
5,870
|
|
Regulated transmission and storage segment
|
|
|
10,102
|
|
|
|
8,454
|
|
|
|
1,648
|
|
Nonregulated segment
|
|
|
6,577
|
|
|
|
33,428
|
|
|
|
(26,851
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
73,997
|
|
|
$
|
93,330
|
|
|
$
|
(19,333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reflects our consolidated net income and
diluted earnings per share in our regulated and nonregulated
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
67,420
|
|
|
$
|
59,902
|
|
|
$
|
7,518
|
|
Nonregulated operations
|
|
|
6,577
|
|
|
|
33,428
|
|
|
|
(26,851
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
73,997
|
|
|
$
|
93,330
|
|
|
$
|
(19,333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
0.74
|
|
|
$
|
0.64
|
|
|
$
|
0.10
|
|
Diluted EPS from nonregulated operations
|
|
|
0.07
|
|
|
|
0.36
|
|
|
|
(0.29
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
0.81
|
|
|
$
|
1.00
|
|
|
$
|
(0.19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
Three
Months Ended December 31, 2010 compared with Three Months
Ended December 31, 2009
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, 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, Kansas, West Texas
|
|
October May
|
Kentucky, Mississippi, Tennessee, Mid-Tex
|
|
November April
|
Louisiana
|
|
December March
|
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.
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.
33
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the three months ended
December 31, 2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
299,772
|
|
|
$
|
294,627
|
|
|
$
|
5,145
|
|
Operating expenses
|
|
|
175,587
|
|
|
|
181,880
|
|
|
|
(6,293
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
124,185
|
|
|
|
112,747
|
|
|
|
11,438
|
|
Miscellaneous income (expense)
|
|
|
(709
|
)
|
|
|
657
|
|
|
|
(1,366
|
)
|
Interest charges
|
|
|
29,719
|
|
|
|
29,678
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
93,757
|
|
|
|
83,726
|
|
|
|
10,031
|
|
Income tax expense
|
|
|
36,439
|
|
|
|
32,278
|
|
|
|
4,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
57,318
|
|
|
$
|
51,448
|
|
|
$
|
5,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
86,790
|
|
|
|
99,314
|
|
|
|
(12,524
|
)
|
Consolidated natural gas distribution transportation
volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
MMcf
|
|
|
33,754
|
|
|
|
35,207
|
|
|
|
(1,453
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
MMcf
|
|
|
120,544
|
|
|
|
134,521
|
|
|
|
(13,977
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.49
|
|
|
$
|
0.46
|
|
|
$
|
0.03
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
4.92
|
|
|
$
|
5.12
|
|
|
$
|
(0.20
|
)
|
The following table shows our operating income by natural gas
distribution division, in order of total rate base, for the
three months ended December 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
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
57,439
|
|
|
$
|
50,381
|
|
|
$
|
7,058
|
|
Kentucky/Mid-States
|
|
|
21,363
|
|
|
|
17,803
|
|
|
|
3,560
|
|
Louisiana
|
|
|
14,961
|
|
|
|
13,407
|
|
|
|
1,554
|
|
West Texas
|
|
|
9,520
|
|
|
|
11,757
|
|
|
|
(2,237
|
)
|
Colorado-Kansas
|
|
|
8,012
|
|
|
|
8,606
|
|
|
|
(594
|
)
|
Mississippi
|
|
|
10,215
|
|
|
|
9,802
|
|
|
|
413
|
|
Other
|
|
|
2,675
|
|
|
|
991
|
|
|
|
1,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
124,185
|
|
|
$
|
112,747
|
|
|
$
|
11,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $5.1 million increase in natural gas distribution gross
profit primarily reflects a $14.1 million increase in rate
adjustments, primarily in the Mid-Tex, Louisiana, Missouri,
Kentucky and Kansas service areas.
34
These increases were partially offset by:
|
|
|
|
|
$4.9 million decrease due to a ten percent decrease in
consolidated throughput caused principally by warmer weather
this fiscal quarter compared to the same period last year in
most of our service areas.
|
|
|
|
$2.7 million decrease in revenue taxes, offset by
revenue-related franchise taxes, as discussed below.
|
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income decreased
$6.3 million, primarily due to the following:
|
|
|
|
|
$2.9 million decrease in franchise taxes.
|
|
|
|
$2.6 million decrease in employee-related expenses.
|
|
|
|
$1.4 million decrease in legal and other administrative
costs.
|
Miscellaneous income decreased $1.4 million primarily due
to a decrease in interest income.
Recent
Ratemaking Developments
Significant ratemaking developments that occurred during the
three months ended December 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
$24.2 million resulting from ratemaking activity became
effective in the quarter ended December 31, 2010 as
summarized below:
|
|
|
|
|
|
|
Annual Increase to
|
|
Rate Action
|
|
Operating Income
|
|
|
|
(In thousands)
|
|
|
Annual rate filing mechanisms
|
|
$
|
23,122
|
|
Other rate activity
|
|
|
1,113
|
|
|
|
|
|
|
|
|
$
|
24,235
|
|
|
|
|
|
|
Additionally, the following ratemaking efforts were in progress
during the first quarter of fiscal 2011 but had not been
completed as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
|
|
Income
|
|
Division
|
|
Rate Action
|
|
Jurisdiction
|
|
Requested
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Atmos Pipeline - Texas
|
|
Rate Case
|
|
Texas Railroad
Commission
|
|
$
|
35,282
|
|
Colorado-Kansas
|
|
Ad Valorem True
Up(1)
|
|
Kansas
|
|
|
685
|
|
Kentucky/Mid-States
|
|
ISRS(2)
|
|
Missouri
|
|
|
382
|
|
Louisiana
|
|
Annual Rate Filing
|
|
TransLa
|
|
|
431
|
|
Mississippi
|
|
Annual Rate Filing
|
|
Mississippi
|
|
|
|
|
West Texas
|
|
Environs Rate Case
|
|
Amarillo
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Ad Valorem filing relates to a collection of property taxes
in excess of the amount included in the Companys base
rates. |
|
(2) |
|
Infrastructure System Replacement Surcharge (ISRS) relates to
maintenance capital investments made since the previous rate
case. |
35
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. There were no fiscal 2011 rate
cases completed as of December 31, 2010.
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 stabilization clause in the
Louisiana Division. The following table summarizes filings made
under our various annual rate filing mechanisms for the quarter
ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
Test Year
|
|
|
Operating
|
|
|
Effective
|
Division
|
|
Jurisdiction
|
|
Ended
|
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
2011 Filings:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Tex
|
|
Settled Cities
|
|
|
12/31/2009
|
|
|
$
|
23,122
|
|
|
10/1/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2011 Filings
|
|
|
|
|
|
|
|
$
|
23,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes other ratemaking activity during
the quarter ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Effective
|
Division
|
|
Jurisdiction
|
|
Rate Activity
|
|
Income
|
|
|
Date
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
2011 Other Rate Activity:
|
|
|
|
|
|
|
|
|
|
|
Colorado-Kansas
|
|
Colorado
|
|
AMI(1)
|
|
$
|
349
|
|
|
12/1/2010
|
Kentucky/Mid-States
|
|
Georgia
|
|
PRP
Surcharge(2)
|
|
|
764
|
|
|
10/1/2010
|
|
|
|
|
|
|
|
|
|
|
|
Total 2011 Other Rate Activity
|
|
|
|
|
|
$
|
1,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Automated Meter Infrastructure (AMI) relates to a pilot program
in the Weld County area of the Companys service area. |
|
(2) |
|
The Pipeline Replacement Program (PRP) surcharge relates to a
long-term cast iron replacement program. |
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.
36
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the three months ended
December 31, 2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
27,535
|
|
|
$
|
26,711
|
|
|
$
|
824
|
|
Third-party transportation
|
|
|
16,512
|
|
|
|
15,242
|
|
|
|
1,270
|
|
Storage and park and lend services
|
|
|
2,170
|
|
|
|
2,605
|
|
|
|
(435
|
)
|
Other
|
|
|
2,790
|
|
|
|
2,302
|
|
|
|
488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
49,007
|
|
|
|
46,860
|
|
|
|
2,147
|
|
Operating expenses
|
|
|
24,926
|
|
|
|
25,788
|
|
|
|
(862
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
24,081
|
|
|
|
21,072
|
|
|
|
3,009
|
|
Miscellaneous income (expense)
|
|
|
(282
|
)
|
|
|
43
|
|
|
|
(325
|
)
|
Interest charges
|
|
|
8,064
|
|
|
|
7,968
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
15,735
|
|
|
|
13,147
|
|
|
|
2,588
|
|
Income tax expense
|
|
|
5,633
|
|
|
|
4,693
|
|
|
|
940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
10,102
|
|
|
$
|
8,454
|
|
|
$
|
1,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
153,178
|
|
|
|
157,773
|
|
|
|
(4,595
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
99,841
|
|
|
|
95,938
|
|
|
|
3,903
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $2.1 million increase in regulated transmission and
storage gross profit was attributable primarily to the following
factors:
|
|
|
|
|
$3.1 million increase associated with our GRIP filings.
|
|
|
|
$1.6 million increase in fixed fee services.
|
These increases were partially offset by the following:
|
|
|
|
|
$1.5 million decrease resulting from lower
per-unit
transportation margins.
|
|
|
|
$1.0 million decrease due to a decline in throughput to our
Mid-Tex Division and a reduction in production.
|
Operating expenses decreased $0.9 million primarily due to
lower levels of pipeline maintenance activities.
Nonregulated
Segment
Our nonregulated activities are conducted through Atmos Energy
Holdings, Inc. (AEH), which is a wholly-owned subsidiary of
Atmos Energy Corporation and operates primarily in the Midwest
and Southeast areas of the United States.
AEHs primary business is to deliver gas and provide
related services by aggregating and purchasing gas supply,
arranging transportation and storage logistics and ultimately
delivering gas to customers at competitive prices. In addition,
AEH utilizes proprietary and customer-owned transportation and
storage assets to provide various delivered gas 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. As a
result, AEHs gas delivery and related services margins
arise from the types of commercial transactions we have
structured with our
37
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.
AEHs storage and transportation margins arise from
(i) utilizing its proprietary
21-mile
pipeline located in New Orleans, Louisiana to aggregate gas
supply for our regulated natural gas distribution division in
Louisiana, its gas delivery activities and, on a more limited
basis, third parties and (ii) managing proprietary storage
in Kentucky and Louisiana to supplement the natural gas needs of
our natural gas distribution divisions during peak periods.
AEH also seeks to enhance its gross profit margin by maximizing,
through asset optimization activities, the economic value
associated with the storage and transportation capacity it owns
or controls in our natural gas distribution and by its
subsidiaries. We attempt to meet these objectives 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 AEH
has access and selling financial instruments at advantageous
prices to lock in a gross profit margin.
AEH continually manages its net physical position to attempt to
increase the future economic profit that was created when the
original transaction was executed. Therefore, AEH 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 AEH elects to accelerate the withdrawal of
physical gas, it will execute new financial instruments to hedge
the original financial instruments. If AEH elects to defer the
withdrawal of gas, it will reset its positions 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.
AEH also uses financial instruments to capture additional
storage arbitrage opportunities that may arise after the
original physical inventory hedge 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 and
differences in natural gas prices between the various markets
that we serve (commonly referred to as basis differentials),
have a significant impact on our nonregulated businesses. Within
our delivered gas activities, basis differentials impact our
ability to create value from identifying the lowest cost
alternative among the natural gas supplies, transportation and
markets to which we have access. Further, 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 nonregulated segment. Increased price volatility often
has a significant impact on the spreads between the market
(spot) prices and forward natural gas prices, which creates
opportunities to earn higher arbitrage spreads within our asset
optimization activities. Volatility could also impact the basis
differentials we capture in our delivered gas activities.
However,
38
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.
Review of
Financial and Operating Results
Financial and operational highlights for our nonregulated
segment for the three months ended December 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, margins earned from storage and
transportation services 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.
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
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas delivery and related services
|
|
$
|
16,041
|
|
|
$
|
16,087
|
|
|
$
|
(46
|
)
|
Storage and transportation services
|
|
|
3,349
|
|
|
|
3,334
|
|
|
|
15
|
|
Other
|
|
|
1,319
|
|
|
|
464
|
|
|
|
855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,709
|
|
|
|
19,885
|
|
|
|
824
|
|
Asset optimization
|
|
|
3,965
|
|
|
|
6,006
|
|
|
|
(2,041
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized margins
|
|
|
24,674
|
|
|
|
25,891
|
|
|
|
(1,217
|
)
|
Unrealized margins
|
|
|
504
|
|
|
|
43,884
|
|
|
|
(43,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
25,178
|
|
|
|
69,775
|
|
|
|
(44,597
|
)
|
Operating expenses
|
|
|
13,335
|
|
|
|
12,998
|
|
|
|
337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
11,843
|
|
|
|
56,777
|
|
|
|
(44,934
|
)
|
Miscellaneous income
|
|
|
290
|
|
|
|
376
|
|
|
|
(86
|
)
|
Interest charges
|
|
|
1,170
|
|
|
|
2,407
|
|
|
|
(1,237
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
10,963
|
|
|
|
54,746
|
|
|
|
(43,783
|
)
|
Income tax expense
|
|
|
4,386
|
|
|
|
21,318
|
|
|
|
(16,932
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
6,577
|
|
|
$
|
33,428
|
|
|
$
|
(26,851
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross nonregulated delivered gas sales volumes MMcf
|
|
|
107,712
|
|
|
|
102,261
|
|
|
|
5,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated nonregulated delivered gas sales
volumes MMcf
|
|
|
94,538
|
|
|
|
87,229
|
|
|
|
7,309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
19.6
|
|
|
|
19.0
|
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
Realized margins for gas delivery, storage and transportation
services and other services were $20.7 million, or
84 percent of total realized margins during the three
months ended December 31, 2010 compared with
$19.9 million, or 77 percent of total realized margins
for the prior-year quarter. The increase reflects the following:
|
|
|
|
|
An eight percent increase in consolidated sales volumes.
|
|
|
|
A decrease in gas delivery
per-unit
margins from $0.16/Mcf in the prior-year quarter to $0.15/Mcf in
the current-year quarter.
|
|
|
|
The $0.9 million increase in other margins primarily
reflects increased margin on sales of gas held in storage in the
current-year quarter compared to the prior-year quarter.
|
The $2.0 million decrease in realized asset optimization
margins from the prior-year quarter primarily reflects the
impact of continued low natural gas market volatility. In the
prior-year quarter, we were able to take advantage of more
favorable trading opportunities in the daily cash market. These
opportunities were not as readily available in the current
quarter. Additionally, we realized lower spread values on the
positions that were closed during the quarter compared with the
prior-year quarter due to the decline in the physical to forward
spread values experienced in the last
12-15 months.
The $43.4 million decrease in unrealized margins is due
primarily to a significant unrealized gain recognized in the
prior-year quarter. The prior-year quarter unrealized gain
resulted from narrowing spreads between the then current cash
prices and forward natural gas prices experienced on AEHs
net physical position and the deferral of physical storage
withdrawals to later in the 2010 fiscal year.
Interest charges decreased $1.2 million primarily due to a
decrease in intercompany borrowings.
Asset
Optimization Activities
AEH monitors the impact of its asset optimization efforts by
estimating the gross profit, before related fees, that it
captured through the purchase and sale of physical natural gas
and the execution of the 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 and related fees is referred to as the potential gross
profit.
We define potential gross profit as the change in AEHs
gross profit 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
injection/withdrawal 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 AEHs economic value and its
potential gross profit (loss) at December 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In millions, unless otherwise noted)
|
|
|
Economic value
|
|
$
|
(2.6
|
)
|
|
$
|
25.7
|
|
Associated unrealized (gains) losses
|
|
|
10.2
|
|
|
|
(27.2
|
)
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
7.6
|
|
|
|
(1.5
|
)
|
Related
fees(1)
|
|
|
(7.9
|
)
|
|
|
(13.3
|
)
|
|
|
|
|
|
|
|
|
|
Potential gross profit (loss)
|
|
$
|
(0.3
|
)
|
|
$
|
(14.8
|
)
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
19.6
|
|
|
|
19.0
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
(1) |
|
Related fees represent the contractual costs to acquire the
storage capacity utilized in our nonregulated segments
asset optimization activities. 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 we have entered
into as of December 31, 2010 and 2009. |
During the quarter ended December 31, 2010, our
nonregulated segments economic value increased from
($7.5) million, or ($0.48)/Mcf at September 30, 2010
to ($2.6) million, or ($0.13)/Mcf. This compares
unfavorably to economic value at December 31, 2009 of
$25.7 million, or $1.35/Mcf.
During the three months ended December 31, 2010, the
increase in our economic value reflected an increase in spread
value resulting from (i) entering into financial hedges
with higher average prices and (ii) reducing the weighted
average cost of gas held in storage by withdrawing higher cost
gas and injecting gas into storage at lower prices. We
anticipate the majority of the economic value and corresponding
reversal of unrealized
mark-to-market
gains will occur in fiscal 2011.
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 AEH 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 December 31,
2010 will be fully realized in the future nor can we predict in
what time periods such realization 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.
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 regularly evaluate our funding strategy and profile to ensure
that we have sufficient liquidity for our short-term and
long-term needs in a cost-effective manner. We also evaluate the
levels of committed borrowing capacity that we require. During
fiscal 2011, we anticipate consolidating our short-term
facilities used for our regulated operations into a single line
of credit. In October 2010, we replaced our $200 million
364-day
revolving credit agreement with a $200 million
180-day
revolving credit agreement that we do not plan to extend or
replace upon expiration. In December 2010, we replaced
AEMs $450 million
364-day
facility with a $200 million, three-year facility.
Our five-year $566.7 million facility will expire in
December 2011. We expect to begin discussions during fiscal 2011
to replace the expiring five-year $566.7 million facility
with a larger multi-year credit facility. We believe our
existing five-year facility will provide adequate short-term
borrowing capacity until we can successfully execute a new
multi-year credit facility.
Our $350 million unsecured 7.375% Senior Notes will
mature in May 2011. We intend to refinance this debt on a
long-term basis through the issuance of
30-year
unsecured senior notes in June 2011. Additionally, we plan to
issue $250 million of
30-year
unsecured senior notes in November 2011 to fund our capital
expenditure program. On September 30, 2010, we entered into
five Treasury lock agreements to fix the Treasury yield
component of the interest cost of financing the anticipated
issuances of senior notes. We designated all of the Treasury
lock agreements as cash flow hedges of an anticipated
transaction. Any realized gain or loss incurred when these
agreements are settled will be recognized as a component of
interest expense over the life of the related long-term debt.
41
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 2011.
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 three months ended December 31, 2010 and 2009 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
2010 vs. 2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Total cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
45,824
|
|
|
$
|
95,156
|
|
|
$
|
(49,332
|
)
|
Investing activities
|
|
|
(123,532
|
)
|
|
|
(117,312
|
)
|
|
|
(6,220
|
)
|
Financing activities
|
|
|
75,648
|
|
|
|
85,782
|
|
|
|
(10,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
(2,060
|
)
|
|
|
63,626
|
|
|
|
(65,686
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
131,952
|
|
|
|
111,203
|
|
|
|
20,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
129,892
|
|
|
$
|
174,829
|
|
|
$
|
(44,937
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
The $49.3 million decrease in operating cash flows
primarily reflects the timing of customer collections and vendor
payments.
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 2011 are expected to range from
$580 million to $595 million. For the three months
ended December 31, 2010, capital expenditures were
$123.2 million compared with $115.4 million for the
three months ended December 31, 2009. The $7.8 million
increase in capital expenditures primarily reflects spending for
the steel service line replacement program in the Mid-Tex
Division and the purchase of software for new customer service
systems in the current quarter partially offset by the
relocation of the companys information technology data
center in the prior-year quarter.
42
Cash
flows from financing activities
The $10.1 million decrease in financing cash flows was
primarily due to the following:
|
|
|
|
|
$10.0 million additional cash used to repay long-term debt
that matured in December 2010, partially offset by
|
|
|
|
$1.3 million additional cash provided from short-term debt
borrowings.
|
The following table summarizes our share issuances for the three
months ended December 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
Direct Stock Purchase Plan
|
|
|
|
|
|
|
79,087
|
|
Retirement Savings Plan and Trust
|
|
|
|
|
|
|
79,722
|
|
1998 Long-Term Incentive Plan
|
|
|
595,103
|
|
|
|
259,550
|
|
Outside Directors
Stock-for-Fee
Plan
|
|
|
638
|
|
|
|
770
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
595,741
|
|
|
|
419,129
|
|
|
|
|
|
|
|
|
|
|
The
quarter-over-quarter
change in the number of shares issued primarily reflects the
fact that we are using shares purchased in the open market
rather than issuing shares for the Direct Stock Purchase Plan
and the Retirement Savings Plan. During the current quarter, we
repurchased 121,353 shares attributable to equity awards
which are not included in the table above.
Share
Repurchase Agreement
On, July 1, 2010, we entered into an accelerated share
repurchase agreement with Goldman Sachs & Co. under
which we repurchased $100 million of our outstanding common
stock in order to offset stock grants made under our various
employee and director incentive compensation plans.
We paid $100 million to Goldman Sachs & Co. on
July 7, 2010 for shares of Atmos Energy common stock in a
share forward transaction and received 2,958,580 shares.
The specific number of shares we will ultimately repurchase in
the transaction will be based generally on the average of the
daily volume-weighted average share price of our common stock
over the duration of the agreement. The agreement is scheduled
to end in the second fiscal quarter of 2011. As a result of this
transaction, beginning in our fourth fiscal quarter of 2010, the
number of outstanding shares used to calculate our earnings per
share was reduced by the number of shares received and the
$100 million purchase price was recorded as a reduction in
shareholders equity. The number of shares used to
calculate our earnings per share in fiscal 2011 will continue to
be reduced by the shares we received in July 2010; however, the
total impact to diluted earnings per share for fiscal 2011 will
be dependent upon the average share price of our common stock
over the remainder of the agreement.
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 $1.0 billion of working
capital funding. As of December 31, 2010, the amount
available to us under our credit facilities, net of outstanding
letters of credit, was approximately $656 million. These
facilities are described in further detail in Note 5 to the
unaudited condensed consolidated financial statements.
43
In October 2010, our $200 million
364-day
facility expired. We replaced the $200 million
364-day
facility before its expiration with a $200 million
180-day
credit facility that will expire in April 2011.
On December 8, 2010, the Company replaced AEMs
existing $450 million
364-day
committed revolving credit facility with a $200 million
three-year facility with an accordion feature that could
increase the Companys borrowing capacity to
$500 million on substantially the same terms, except for a
slight reduction in the rate of interest charged for both base
rate and offshore borrowings and an extension of the facility
for an additional three-year period. As a result of
consolidating and reducing the amounts available under our
facilities, we expect to reduce our short-term financing costs.
Shelf
Registration
We have an effective shelf registration statement with the
Securities and Exchange Commission (SEC) that permits us to
issue a total of $1.3 billion in common stock
and/or debt
securities. The shelf registration statement has been approved
by all requisite state regulatory commissions. 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.
At December 31, 2010, no amounts have been drawn down on
the shelf registration statement.
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). As of
December 31, 2010, S&P maintained a stable outlook,
while Moodys and Fitch maintained their ratings outlooks
as positive. 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
adverse 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
S&P is AAA, Moodys is Aaa and Fitch is AAA. The
lowest investment grade credit rating for S&P is BBB-,
Moodys is Baa3 and Fitch is BBB-. 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
December 31, 2010. Our debt covenants are described in
greater detail in Note 5 to the unaudited condensed
consolidated financial statements.
44
Capitalization
The following table presents our capitalization inclusive of
short-term debt and the current portion of long-term debt as of
December 31, 2010, September 30, 2010 and
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
September 30, 2010
|
|
|
December 31, 2009
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
247,993
|
|
|
|
5.3
|
%
|
|
$
|
126,100
|
|
|
|
2.8
|
%
|
|
$
|
179,712
|
|
|
|
3.9
|
%
|
Long-term debt
|
|
|
2,159,753
|
|
|
|
46.1
|
%
|
|
|
2,169,682
|
|
|
|
48.5
|
%
|
|
|
2,169,601
|
|
|
|
47.1
|
%
|
Shareholders equity
|
|
|
2,274,853
|
|
|
|
48.6
|
%
|
|
|
2,178,348
|
|
|
|
48.7
|
%
|
|
|
2,258,076
|
|
|
|
49.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,682,599
|
|
|
|
100.0
|
%
|
|
$
|
4,474,130
|
|
|
|
100.0
|
%
|
|
$
|
4,607,389
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt as a percentage of total capitalization, including
short-term debt, was 51.4 percent at December 31,
2010, 51.3 percent at September 30, 2010 and
51.0 percent at December 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 three months ended
December 31, 2010.
As we previously discussed in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2010, 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 provided the third party with the exclusive option to
develop the proposed Fort Necessity salt-dome natural gas
storage project. In July 2010, we signed an extension to the
option and acquisition agreement which gave the third party
until March 2011 to exercise the option to develop the project.
In January 2011, the third party developer notified us that it
did not plan to commence the activities required to allow it to
exercise the option by March 2011, accordingly, the option was
terminated. We are currently evaluating our strategic
alternatives with respect to this project.
Risk
Management Activities
We conduct risk management activities through our natural gas
distribution and nonregulated 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 nonregulated segment, 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.
45
The following table shows the components of the change in fair
value of our natural gas distribution segments financial
instruments for the three months ended December 31, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(49,600
|
)
|
|
$
|
(14,166
|
)
|
Contracts realized/settled
|
|
|
(32,981
|
)
|
|
|
(21,029
|
)
|
Fair value of new contracts
|
|
|
531
|
|
|
|
(947
|
)
|
Other changes in value
|
|
|
108,856
|
|
|
|
18,672
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
$
|
26,806
|
|
|
$
|
(17,470
|
)
|
|
|
|
|
|
|
|
|
|
The fair value of our natural gas distribution segments
financial instruments at December 31, 2010 is presented
below by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at December 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
|
|
$
|
27,709
|
|
|
$
|
(903
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
26,806
|
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
27,709
|
|
|
$
|
(903
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
26,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows the components of the change in fair
value of our nonregulated segments financial instruments
for the three months ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
December 31
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(12,374
|
)
|
|
$
|
26,698
|
|
Contracts realized/settled
|
|
|
934
|
|
|
|
(2,212
|
)
|
Fair value of new contracts
|
|
|
|
|
|
|
|
|
Other changes in value
|
|
|
759
|
|
|
|
7,820
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
|
(10,681
|
)
|
|
|
32,306
|
|
Netting of cash collateral
|
|
|
25,296
|
|
|
|
(1,315
|
)
|
|
|
|
|
|
|
|
|
|
Cash collateral and fair value of contracts at period end
|
|
$
|
14,615
|
|
|
$
|
30,991
|
|
|
|
|
|
|
|
|
|
|
The fair value of our nonregulated segments financial
instruments at December 31, 2010 is presented below by time
period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at December 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
|
|
$
|
(4,199
|
)
|
|
$
|
(6,467
|
)
|
|
$
|
(15
|
)
|
|
$
|
|
|
|
$
|
(10,681
|
)
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(4,199
|
)
|
|
$
|
(6,467
|
)
|
|
$
|
(15
|
)
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$
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$
|
(10,681
|
)
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46
Pension
and Postretirement Benefits Obligations
For the three months ended December 31, 2010 and 2009, our
total net periodic pension and other benefits cost was
$14.9 million and $12.7 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 2011 costs were determined using a September 30,
2010 measurement date. As of September 30, 2010, 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, 2009, the measurement date
for our fiscal 2010 net periodic cost. Accordingly, we
decreased our discount rate used to determine our fiscal 2011
pension and benefit costs to 5.39 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. Accordingly, our fiscal 2011 pension and
postretirement medical costs for the quarter ended
December 31, 2010 were significantly higher than the
prior-year quarter.
In August 2010, the Board of Directors of Atmos Energy approved
a proposal to close the Pension Account Plan (PAP) to new
participants, effective October 1, 2010. Employees
participating in the PAP as of October 1, 2010 were allowed
to make a one-time election to migrate from the PAP into our
defined contribution plan with enhanced features, effective
January 1, 2011. Participants who chose to remain in the
PAP will continue to earn benefits and interest allocations with
no changes to their existing benefits. During the first quarter
ended December 31, 2010, a limited number of participants
elected to join the new plan, which resulted in an immaterial
curtailment gain and a revaluation of the net periodic pension
cost for the remainder of fiscal 2011. The curtailment gain will
be recorded in our second fiscal quarter. The revaluation of the
net periodic pension cost resulted in an increase in the
discount rate, effective January 1, 2011 to
5.68 percent, which will reduce our net periodic pension
cost by approximately $1.8 million for the remainder of the
fiscal year. All other actuarial assumptions remained the same.
In accordance with the Pension Protection Act of 2006 (PPA), we
determined the funded status of our plans as of January 1,
2011. Based upon this valuation, we expect we will be required
to contribute less than $2 million to our pension plans by
September 15, 2011. 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 $11 million to these
plans during fiscal 2011.
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.
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, 2010. During the
three months ended December 31, 2010, there were no
material changes in our quantitative and qualitative disclosures
about market risk.
47
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 December 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.
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 first quarter of the fiscal
year ended September 30, 2011 that have materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
PART II.
OTHER INFORMATION
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Item 1.
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Legal
Proceedings
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During the three months ended December 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, 2010. 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.
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.
48
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)
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By:
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/s/ Fred
E. Meisenheimer
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Fred E. Meisenheimer
Senior Vice President, Chief Financial
Officer and Treasurer
(Duly authorized signatory)
Date: February 9, 2011
49
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Page Number or
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Exhibit
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Incorporation by
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Number
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Description
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Reference to
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10
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.1
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Revolving Credit Agreement (180 Day Facility), dated as of
October 15, 2010, among Atmos Energy Corporation, the Lenders
from time to time parties thereto, SunTrust Bank as
Administrative Agent, Wells Fargo Bank, N.A. as Syndication
Agent, and Bank of America, N.A. and U.S. Bank National
Association as Co-Documentation Agents
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Exhibit 10.1 to Form 8-K dated October 15, 2010 (File No.
1-10042)
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10
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.2
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Fifth Amended and Restated Credit Agreement, dated as of
December 8, 2010 among Atmos Energy Marketing, LLC, a Delaware
limited liability company, BNP Paribas, a bank organized under
the laws of France, as administrative agent, collateral agent,
as an issuing bank, a swing line bank and a bank;
Société Générale as co-syndication agent, an
issuing bank and a bank and the Royal Bank of Scotland, plc, as
co-syndication agent and a bank; and Natixis, New York Branch,
Credit Agricole Corporate and Investment Bank, and Cooperatieve
Centrale Raiffeisen-Boerenleenbank B.A. as co-documentation
agents and the other financial institutions that become parties
thereto
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Exhibit 10.1 to Form 8-K dated December 8, 2010 (File No.
1-10042)
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10
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.3
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Third Amended and Restated Intercreditor Agreement, dated as of
December 8, 2010 (as amended, supplemented and otherwise
modified from time to time, the Agreement), among
BNP Paribas, a bank organized under the laws of France, in its
capacity as Collateral Agent (together with its successors and
assigns in such capacity, the Agent) for the Banks
thereinafter referred to, and each bank and other financial
institution which is now or hereafter a party to the Agreement
in its capacity as a Bank and, as applicable, as a Swap Bank
(collectively, the Swap Banks) and/or a Physical
Trade Bank (collectively, the Physical Trade Banks)
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Exhibit 10.2 to Form 8-K dated December 8, 2010 (File No.
1-10042)
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12
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Computation of ratio of earnings to fixed charges
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15
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Letter regarding unaudited interim financial information
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31
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Rule 13a-14(a)/15d-14(a) Certifications
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32
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Section 1350 Certifications*
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101
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.INS
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XBRL Instance Document**
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101
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.SCH
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XBRL Taxonomy Extension Schema**
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101
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.CAL
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XBRL Taxonomy Extension Calculation Linkbase**
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101
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.LAB
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XBRL Taxonomy Extension Labels Linkbase**
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101
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.PRE
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XBRL Taxonomy Extension Presentation Linkbase**
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* |
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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. |
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** |
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Pursuant to Rule 406T of
Regulation S-T,
the Interactive Data Files on Exhibit 101 hereto are deemed
not filed or part of a registration statement or prospectus for
purposes of Sections 11 or 12 of the Securities Act of
1933, as amended, are deemed not filed for purposes of Section
18 of the Securities and Exchange Act of 1934, as amended, and
otherwise are not subject to liability under those sections. |
50