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
June 30, 2008
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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
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75-1743247
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(State or other jurisdiction
of
incorporation or organization)
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(IRS employer
identification no.)
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Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
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75240
(Zip code)
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(Address of principal executive
offices)
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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 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):
Large Accelerated
Filer þ Accelerated
Filer o Non-Accelerated
Filer o Smaller
Reporting
Company o
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act) Yes o No þ
Number of shares outstanding of each of the issuers
classes of common stock, as of July 31, 2008.
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Class
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Shares Outstanding
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No Par Value
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90,627,522
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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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AES
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Atmos Energy Services, LLC
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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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EITF
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Emerging Issues Task Force
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FASB
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Financial Accounting Standards Board
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FIN
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FASB Interpretation
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Fitch
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Fitch Ratings, Ltd.
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GRIP
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Gas Reliability Infrastructure Program
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KCC
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Kansas Corporation Commission
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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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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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RRC
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Railroad Commission of Texas
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RSC
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Rate Stabilization Clause
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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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SFAS
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Statement of Financial Accounting Standards
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TRA
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Tennessee Regulatory Authority
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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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June 30,
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September 30,
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2008
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2007
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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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5,604,416
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$
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5,396,070
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Less accumulated depreciation and amortization
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1,591,528
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1,559,234
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Net property, plant and equipment
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4,012,888
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3,836,836
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Current assets
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Cash and cash equivalents
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46,501
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60,725
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Cash held on deposit in margin account
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62,152
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Accounts receivable, net
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601,164
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380,133
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Gas stored underground
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571,532
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515,128
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Other current assets
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115,609
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|
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112,909
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|
|
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Total current assets
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1,396,958
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1,068,895
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Goodwill and intangible assets
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737,221
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737,692
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Deferred charges and other assets
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237,723
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253,494
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|
|
|
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|
|
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|
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$
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6,384,790
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$
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5,896,917
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|
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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);
200,000,000 shares authorized; issued and outstanding:
June 30, 2008 90,571,457 shares;
September 30, 2007 89,326,537 shares
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|
$
|
453
|
|
|
$
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447
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Additional paid-in capital
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|
1,732,775
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1,700,378
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Retained earnings
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|
371,486
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|
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281,127
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Accumulated other comprehensive income (loss)
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693
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|
|
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(16,198
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)
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|
|
|
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Shareholders equity
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2,105,407
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1,965,754
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Long-term debt
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2,119,729
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2,126,315
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|
|
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Total capitalization
|
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4,225,136
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4,092,069
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Current liabilities
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Accounts payable and accrued liabilities
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582,353
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355,255
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Other current liabilities
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472,088
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409,993
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Short-term debt
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113,257
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150,599
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Current maturities of long-term debt
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1,059
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3,831
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Total current liabilities
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1,168,757
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919,678
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Deferred income taxes
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450,669
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370,569
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Regulatory cost of removal obligation
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280,108
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271,059
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Deferred credits and other liabilities
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260,120
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243,542
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$
|
6,384,790
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|
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$
|
5,896,917
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
2
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
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|
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Three Months Ended
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June 30
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2008
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2007
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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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$
|
676,639
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|
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$
|
548,251
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Regulated transmission and storage segment
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|
|
46,286
|
|
|
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36,707
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Natural gas marketing segment
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1,189,722
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|
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854,167
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Pipeline, storage and other segment
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3,880
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|
|
|
2,073
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Intersegment eliminations
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(277,382
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)
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(223,046
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)
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|
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1,639,145
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|
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1,218,152
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Purchased gas cost
|
|
|
|
|
|
|
|
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Natural gas distribution segment
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|
476,711
|
|
|
|
357,608
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Regulated transmission and storage segment
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|
|
|
|
|
|
|
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Natural gas marketing segment
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|
|
1,192,353
|
|
|
|
854,743
|
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Pipeline, storage and other segment
|
|
|
706
|
|
|
|
228
|
|
Intersegment eliminations
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|
(276,847
|
)
|
|
|
(222,443
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)
|
|
|
|
|
|
|
|
|
|
|
|
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1,392,923
|
|
|
|
990,136
|
|
|
|
|
|
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|
|
|
|
Gross profit
|
|
|
246,222
|
|
|
|
228,016
|
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Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
117,822
|
|
|
|
115,141
|
|
Depreciation and amortization
|
|
|
50,356
|
|
|
|
48,974
|
|
Taxes, other than income
|
|
|
57,335
|
|
|
|
52,881
|
|
Impairment of long-lived assets
|
|
|
|
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
225,513
|
|
|
|
220,285
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
20,709
|
|
|
|
7,731
|
|
Miscellaneous income
|
|
|
1,600
|
|
|
|
4,266
|
|
Interest charges
|
|
|
33,470
|
|
|
|
34,479
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(11,161
|
)
|
|
|
(22,482
|
)
|
Income tax benefit
|
|
|
(4,573
|
)
|
|
|
(9,122
|
)
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
|
|
|
|
|
|
|
|
Basic net loss per share
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
Diluted net loss per share
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.325
|
|
|
$
|
0.320
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
89,648
|
|
|
|
88,366
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
89,648
|
|
|
|
88,366
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
3,126,672
|
|
|
$
|
2,973,528
|
|
Regulated transmission and storage segment
|
|
|
142,772
|
|
|
|
122,647
|
|
Natural gas marketing segment
|
|
|
3,159,092
|
|
|
|
2,360,902
|
|
Pipeline, storage and other segment
|
|
|
20,629
|
|
|
|
27,483
|
|
Intersegment eliminations
|
|
|
(668,525
|
)
|
|
|
(588,193
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
5,780,640
|
|
|
|
4,896,367
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
2,296,020
|
|
|
|
2,174,071
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
3,099,428
|
|
|
|
2,275,291
|
|
Pipeline, storage and other segment
|
|
|
1,773
|
|
|
|
682
|
|
Intersegment eliminations
|
|
|
(666,835
|
)
|
|
|
(585,971
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
4,730,386
|
|
|
|
3,864,073
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,050,254
|
|
|
|
1,032,294
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
359,064
|
|
|
|
342,373
|
|
Depreciation and amortization
|
|
|
147,659
|
|
|
|
149,035
|
|
Taxes, other than income
|
|
|
153,170
|
|
|
|
149,694
|
|
Impairment of long-lived assets
|
|
|
|
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
659,893
|
|
|
|
644,391
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
390,361
|
|
|
|
387,903
|
|
Miscellaneous income
|
|
|
2,974
|
|
|
|
7,683
|
|
Interest charges
|
|
|
103,803
|
|
|
|
109,273
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
289,532
|
|
|
|
286,313
|
|
Income tax expense
|
|
|
110,783
|
|
|
|
111,907
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
2.00
|
|
|
$
|
2.02
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
1.99
|
|
|
$
|
2.00
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.975
|
|
|
$
|
0.960
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
89,281
|
|
|
|
86,378
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
89,937
|
|
|
|
87,011
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
Charged to depreciation and amortization
|
|
|
147,659
|
|
|
|
149,035
|
|
Charged to other accounts
|
|
|
106
|
|
|
|
148
|
|
Deferred income taxes
|
|
|
77,864
|
|
|
|
37,266
|
|
Other
|
|
|
12,767
|
|
|
|
17,959
|
|
Net assets / liabilities from risk management activities
|
|
|
35,169
|
|
|
|
12,325
|
|
Net change in operating assets and liabilities
|
|
|
(34,933
|
)
|
|
|
161,531
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
417,381
|
|
|
|
552,670
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(312,878
|
)
|
|
|
(263,023
|
)
|
Other, net
|
|
|
(4,303
|
)
|
|
|
(9,867
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(317,181
|
)
|
|
|
(272,890
|
)
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Net decrease in short-term debt
|
|
|
(35,721
|
)
|
|
|
(382,416
|
)
|
Net proceeds from long-term debt offering
|
|
|
|
|
|
|
247,461
|
|
Settlement of Treasury lock agreement
|
|
|
|
|
|
|
4,750
|
|
Repayment of long-term debt
|
|
|
(9,945
|
)
|
|
|
(2,685
|
)
|
Cash dividends paid
|
|
|
(87,821
|
)
|
|
|
(83,118
|
)
|
Issuance of common stock
|
|
|
19,063
|
|
|
|
18,883
|
|
Net proceeds from equity offering
|
|
|
|
|
|
|
191,913
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(114,424
|
)
|
|
|
(5,212
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(14,224
|
)
|
|
|
274,568
|
|
Cash and cash equivalents at beginning of period
|
|
|
60,725
|
|
|
|
75,815
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
46,501
|
|
|
$
|
350,383
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
5
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2008
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. Through our natural gas distribution business, we
deliver natural gas through sales and transportation
arrangements to approximately 3.2 million residential,
commercial, public authority and industrial customers through
our six regulated natural gas distribution divisions in the
service areas described below:
|
|
|
Division
|
|
Service Area
|
|
Atmos Energy Colorado-Kansas Division
|
|
Colorado, Kansas,
Missouri(1)
|
Atmos Energy Kentucky/Mid-States Division
|
|
Georgia(1),
Illinois(1),
Iowa(1),
Kentucky,
Missouri(1)
Tennessee,
Virginia(1)
|
Atmos Energy Louisiana Division
|
|
Louisiana
|
Atmos Energy Mid-Tex Division
|
|
Texas, including the Dallas/Fort Worth metropolitan area
|
Atmos Energy Mississippi Division
|
|
Mississippi
|
Atmos Energy West Texas Division
|
|
West Texas
|
|
|
|
(1) |
|
Denotes states where we have more limited service areas. |
In addition, we transport natural gas for others through our
distribution system. Our natural gas distribution business is
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 corporate
headquarters and shared-services function are located in Dallas,
Texas, and our customer support centers are located in Amarillo
and Waco, Texas.
Our regulated transmission and storage business consists of the
regulated operations of our Atmos Pipeline Texas
Division. The Atmos Pipeline Texas Division
transports natural gas to our Mid-Tex Division, transports
natural gas for third parties and manages five underground
storage reservoirs in Texas. We also provide ancillary services
customary to the pipeline industry including parking
arrangements, lending and sales of inventory on hand. Parking
arrangements provide short-term interruptible storage of gas on
our pipeline. Lending services provide short-term interruptible
loans of natural gas from our pipeline to meet market demands.
Our nonregulated businesses operate primarily in the Midwest and
Southeast and include our natural gas marketing operations and
pipeline, storage and other operations. These businesses are
operated through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc. (AEH), which is wholly-owned by the
Company and based in Houston, Texas.
Our natural gas marketing operations are managed by Atmos Energy
Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides
a variety of natural gas management services to municipalities,
natural gas utility systems and industrial natural gas
customers, primarily in the southeastern and midwestern states
and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana
divisions. These services consist primarily of 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 derivative
instruments.
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our pipeline, storage and other segment primarily consists of
the operations of Atmos Pipeline and Storage, LLC (APS), Atmos
Energy Services, LLC (AES) and Atmos Power Systems, Inc., each
of which are wholly-owned by AEH. APS owns or has an interest in
underground storage fields in Kentucky and Louisiana. We use
these storage facilities to reduce the need to contract for
additional pipeline capacity to meet customer demand during peak
periods. Additionally, APS manages our natural gas gathering
operations, which were limited in nature as of June 30,
2008. AES provides limited services to our natural gas
distribution divisions, and the revenues AES receives are equal
to the costs incurred to provide those services. Through Atmos
Power Systems, Inc., we have constructed electric peaking
power-generating plants and associated facilities and lease
these plants through lease agreements that are accounted for as
sales under generally accepted accounting principles.
|
|
2.
|
Unaudited
Interim Financial Information
|
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 its
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2007. Because of
seasonal and other factors, the results of operations for the
three and
nine-month
periods ended June 30, 2008 are not indicative of our
results of operations for the full 2008 fiscal year, which ends
September 30, 2008.
Significant
accounting policies
Our accounting policies are described in Note 2 to the
financial statements in our Annual Report on
Form 10-K
for the year ended September 30, 2007. Except for the
Companys adoption of FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation
of FASB Statement No. 109 (FIN 48), discussed
below, there were no significant changes to those accounting
policies during the nine months ended June 30, 2008.
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation
of FASB Statement No. 109. FIN 48 addresses the
determination of whether tax benefits claimed or expected to be
claimed on a tax return should be recorded in the financial
statements. Under FIN 48, the Company may recognize the tax
benefit from uncertain tax positions only if it is at least more
likely than not that the tax position will be sustained on
examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the
financial statements from such a position should be measured
based on the largest benefit that has a greater than fifty
percent likelihood of being realized upon settlement with the
taxing authorities. FIN 48 also provides guidance on
derecognition, classification, interest and penalties on income
taxes, accounting in interim periods and requires increased
disclosures.
We adopted the provisions of FIN 48 on October 1,
2007. As a result of adopting FIN 48, we determined that we
had $6.1 million of liabilities associated with uncertain
tax positions. Of this amount, $0.5 million was recognized
as a result of adopting FIN 48 with an offsetting reduction
to retained earnings.
Prior to October 1, 2007, the $5.6 million liability
previously recorded for uncertain tax positions was reflected on
the consolidated balance sheet as a component of deferred income
taxes. As a result of adopting FIN 48, we recorded a
$3.7 million liability as a component of other current
liabilities and $2.4 million as a component of deferred
credits and other liabilities, with offsetting decreases to the
deferred income tax liability.
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of June 30, 2008, we had recorded liabilities associated
with uncertain tax positions totaling $8.0 million. The
realization of all of these tax benefits would reduce our income
tax expense by approximately $8.0 million.
The following table presents the changes in unrecognized tax
benefits for the nine months ended June 30, 2008 (in
thousands):
|
|
|
|
|
Total unrecognized tax benefits at October 1, 2007
|
|
$
|
6,156
|
|
Gross increases for current years tax positions
|
|
|
|
|
Gross increases for prior years tax positions
|
|
|
2,331
|
|
Gross decreases for prior years tax positions
|
|
|
(528
|
)
|
Settlements
|
|
|
|
|
|
|
|
|
|
Total unrecognized tax benefits at June 30, 2008
|
|
$
|
7,959
|
|
|
|
|
|
|
We recognize accrued interest related to unrecognized tax
benefits as a component of interest expense. We recognize
penalties related to unrecognized tax benefits as a component of
miscellaneous income (expense) in accordance with regulatory
requirements. We did not recognize any material penalty and
interest expenses during the nine months ended June 30,
2008.
We file income tax returns in the U.S. federal jurisdiction
as well as in various states where we have operations. We have
concluded substantially all U.S. federal income tax matters
through fiscal year 2001. The Internal Revenue Service is
currently conducting a routine examination of our fiscal 2002,
2003 and 2004 tax returns, and we anticipate these examinations
will be completed by the end of fiscal 2008. We believe all
material tax items which relate to the years under audit have
been properly accrued.
Additionally, during the second quarter of fiscal 2008, we
completed our annual goodwill impairment assessment. Based on
the assessment performed, we determined that our goodwill was
not impaired.
Regulatory
assets and liabilities
We record certain costs as regulatory assets in accordance with
Statement of Financial Accounting Standards (SFAS) 71,
Accounting for the Effects of Certain Types of Regulation,
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.
8
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Significant regulatory assets and liabilities as of
June 30, 2008 and September 30, 2007 included the
following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
52,623
|
|
|
$
|
59,022
|
|
Merger and integration costs, net
|
|
|
7,689
|
|
|
|
7,996
|
|
Deferred gas costs
|
|
|
21,473
|
|
|
|
14,797
|
|
Environmental costs
|
|
|
1,014
|
|
|
|
1,303
|
|
Rate case costs
|
|
|
13,758
|
|
|
|
10,989
|
|
Deferred franchise fees
|
|
|
690
|
|
|
|
796
|
|
Other
|
|
|
8,474
|
|
|
|
10,719
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
105,721
|
|
|
$
|
105,622
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
109,439
|
|
|
$
|
84,043
|
|
Regulatory cost of removal obligation
|
|
|
300,994
|
|
|
|
295,241
|
|
Deferred income taxes, net
|
|
|
165
|
|
|
|
165
|
|
Other
|
|
|
7,292
|
|
|
|
7,503
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
417,890
|
|
|
$
|
386,952
|
|
|
|
|
|
|
|
|
|
|
Currently, our authorized rates do not include a return on
certain of our merger and integration costs; however, we recover
the amortization of these costs. Merger and integration costs,
net, are generally amortized on a straight-line basis over
estimated useful lives ranging up to 20 years.
Environmental costs have been deferred to be included in future
rate filings in accordance with rulings received from various
state regulatory commissions.
9
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Comprehensive
income
The following table presents the components of comprehensive
income (loss), net of related tax, for the three-month and
nine-month periods ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
Unrealized holding gains (losses) on investments, net of tax
expense (benefit) of $531 and $215 for the three months ended
June 30, 2008 and 2007 and of $(140) and $964 for the nine
months ended June 30, 2008 and 2007
|
|
|
866
|
|
|
|
353
|
|
|
|
(231
|
)
|
|
|
1,575
|
|
Amortization and unrealized gain on interest rate hedging
transactions, net of tax expense of $482 and $1,863 for the
three months ended June 30, 2008 and 2007 and $1,446 and
$3,373 for the nine months ended June 30, 2008 and 2007
|
|
|
787
|
|
|
|
3,039
|
|
|
|
2,361
|
|
|
|
5,501
|
|
Net unrealized gains (losses) on commodity hedging transactions,
net of tax expense (benefit) of $1,850 and $(2,832) for the
three months ended June 30, 2008 and 2007 and $9,047 and
$12,504 for the nine months ended June 30, 2008 and 2007
|
|
|
3,018
|
|
|
|
(4,621
|
)
|
|
|
14,761
|
|
|
|
20,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(1,917
|
)
|
|
$
|
(14,589
|
)
|
|
$
|
195,640
|
|
|
$
|
201,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss), net of tax, as of
June 30, 2008 and September 30, 2007 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
Unrealized holding gains on investments
|
|
$
|
2,576
|
|
|
$
|
2,807
|
|
Treasury lock agreements
|
|
|
(11,891
|
)
|
|
|
(14,252
|
)
|
Cash flow hedges
|
|
|
10,008
|
|
|
|
(4,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
693
|
|
|
$
|
(16,198
|
)
|
|
|
|
|
|
|
|
|
|
Recently
issued accounting pronouncements
In March 2008, the Financial Accounting Standards Board (FASB)
issued FASB Statement No. 161, Disclosures about
Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133. SFAS 161 expands the
disclosure requirements for derivative instruments and for
hedging activities. This statement requires specific disclosures
regarding how and why an entity uses derivative instruments; how
derivative instruments and related hedged items are accounted
for; and how derivative instruments and related hedged items
affect an entitys financial position, results of
operations and cash flows. The provisions of this standard will
be effective for us beginning January 1, 2009. Since
SFAS 161 only requires additional disclosures concerning
derivatives and hedging activities, this standard is not
expected to have a material impact on our financial position,
results of operations or cash flows.
In December 2007, the FASB issued FASB Statement No. 141
(revised 2007), Business Combinations. SFAS 141(R)
establishes principles and requirements for how the acquirer in
a business combination recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities
assumed and any noncontrolling interest in the acquiree at the
acquisition date fair value. SFAS 141(R) significantly
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
changes the accounting for business combinations in a number of
areas, including the treatment of contingent consideration,
preacquisition contingencies, transaction costs and
restructuring costs. In addition, under SFAS 141(R),
changes in an acquired entitys deferred tax assets and
uncertain tax positions after the measurement period will impact
income tax expense. The provisions of this standard will apply
to any acquisitions we may complete after October 1, 2009.
In December 2007, the FASB issued FASB Statement No. 160,
Noncontrolling Interests in Consolidated Financial Statement,
an amendment of ARB No. 51. SFAS 160 changes the
accounting and reporting for minority interests, which will be
recharacterized as noncontrolling interests and classified as a
component of equity. This new consolidation method significantly
changes the accounting for transactions with minority interest
holders. The provisions of the standard will be effective for us
beginning October 1, 2009. This standard is not expected to
have a material impact on our financial position, results of
operations or cash flows.
|
|
3.
|
Derivative
Instruments and Hedging Activities
|
We conduct risk management activities through both our natural
gas distribution and natural gas marketing segments. We record
our derivatives as a component of risk management assets and
liabilities, which are classified as current or noncurrent other
assets or liabilities based upon the anticipated settlement date
of the underlying derivative. Our determination of the fair
value of these derivative financial instruments reflects the
estimated amounts that we would receive or pay to terminate or
close the contracts at the reporting date, taking into account
the current unrealized gains and losses on open contracts. In
our determination of fair value, we consider various factors,
including closing exchange and over-the-counter quotations, time
value and volatility factors underlying the contracts. These
risk management assets and liabilities are subject to continuing
market risk until the underlying derivative contracts are
settled.
The following table shows the fair values of our risk management
assets and liabilities by segment at June 30, 2008 and
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management activities, current
|
|
$
|
37,366
|
|
|
$
|
5,534
|
|
|
$
|
42,900
|
|
Assets from risk management activities, noncurrent
|
|
|
|
|
|
|
5,904
|
|
|
|
5,904
|
|
Liabilities from risk management activities, current
|
|
|
|
|
|
|
(50,686
|
)
|
|
|
(50,686
|
)
|
Liabilities from risk management activities, noncurrent
|
|
|
|
|
|
|
(3,724
|
)
|
|
|
(3,724
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
37,366
|
|
|
$
|
(42,972
|
)
|
|
$
|
(5,606
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management activities, current
|
|
$
|
|
|
|
$
|
21,849
|
|
|
$
|
21,849
|
|
Assets from risk management activities, noncurrent
|
|
|
|
|
|
|
5,535
|
|
|
|
5,535
|
|
Liabilities from risk management activities, current
|
|
|
(21,053
|
)
|
|
|
(286
|
)
|
|
|
(21,339
|
)
|
Liabilities from risk management activities, noncurrent
|
|
|
|
|
|
|
(290
|
)
|
|
|
(290
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
(21,053
|
)
|
|
$
|
26,808
|
|
|
$
|
5,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Natural
Gas Distribution Derivative Activities
In our natural gas distribution segment, we use a combination of
physical storage and financial derivatives to partially insulate
our natural gas distribution customers against gas price
volatility during the winter heating season. These financial
derivatives have not been designated as hedges pursuant to
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities. Accordingly, they are recorded at fair
value. However, because the costs associated with and the gains
and losses arising from these financial derivatives are included
in our purchased gas adjustment mechanisms, changes in the fair
value of these financial derivatives are initially recorded as a
component of deferred gas costs and recognized in the
consolidated statement of income as a component of purchased gas
costs when the related costs are recovered through our rates in
accordance with SFAS 71. Accordingly, there is no earnings
impact to our natural gas distribution segment as a result of
the use of financial derivatives.
Natural
Gas Marketing Derivative Activities
Our natural gas marketing risk management activities are
conducted through AEM. AEM is exposed to risks associated with
changes in the market price of natural gas, and we manage our
exposure to the risk of natural gas price changes through a
combination of physical storage and financial derivatives,
including futures, over-the-counter and exchange-traded options
and swap contracts with counterparties. AEM uses financial
derivatives designated as fair value hedges to offset changes in
the fair value of its natural gas inventory and derivatives
designated as cash flow hedges to offset anticipated purchases
and sales of gas in the future. AEM also utilizes basis swaps
and other non-hedge derivative instruments to manage its
exposure to market volatility.
Pipeline,
Storage and Other Derivative Activities
Our pipeline, storage and other activities are also exposed to
risks associated with changes in the market price of natural
gas, which are managed through a combination of physical storage
and financial derivatives, including futures, over-the-counter
and exchange-traded options and swap contracts with
counterparties. Atmos Pipeline and Storage, LLC uses financial
derivatives designated as fair value hedges to offset changes in
the fair value of its natural gas inventory.
Under our risk management policies for our nonregulated
operations, we seek to match our financial derivative positions
to our physical storage positions as well as our expected
current and future sales and purchase obligations to maintain no
net 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. We may
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
June 30, 2008, AEH had a net open position (including
existing storage) of 0.1 Bcf.
Treasury
Derivative Activities
We periodically manage our exposure to interest rate changes by
entering into Treasury lock agreements to fix the Treasury yield
component of the interest cost associated with anticipated
financings. Since fiscal 2004, we have executed five Treasury
lock agreements.
The most recent treasury lock agreement was executed in March
2007, which fixed the Treasury yield component of the interest
cost associated with $100 million of our $250 million
6.35% Senior Notes that were
12
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
issued in June 2007. This Treasury lock agreement was settled in
June 2007, and resulted in the receipt of $4.8 million from
the counterparties.
The settlement of the five Treasury lock agreements resulted in
a net $39.0 million payment to the counterparties. We
designated these Treasury lock agreements as a cash flow hedge
of an anticipated transaction at the time the agreements were
executed. Accordingly, unrealized gains and losses associated
with the Treasury lock agreements were recorded as a component
of accumulated other comprehensive income. The net realized loss
recognized upon settlement of the Treasury lock agreements was
initially recorded as a component of accumulated other
comprehensive income and is currently being recognized as a
component of interest expense over the life of the related
financing arrangements.
The following table summarizes the gains and losses arising from
hedging transactions that were recognized as a component of
other comprehensive income (loss), net of taxes, for the three
and nine months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
|
|
|
$
|
2,204
|
|
|
$
|
|
|
|
$
|
2,945
|
|
Forward commodity contracts
|
|
|
6,636
|
|
|
|
(4,750
|
)
|
|
|
16,285
|
|
|
|
(6,975
|
)
|
Recognition of (gains) losses in earnings due to
settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
787
|
|
|
|
835
|
|
|
|
2,361
|
|
|
|
2,556
|
|
Forward commodity contracts
|
|
|
(3,618
|
)
|
|
|
129
|
|
|
|
(1,524
|
)
|
|
|
27,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) from hedging, net of
tax(1)
|
|
$
|
3,805
|
|
|
$
|
(1,582
|
)
|
|
$
|
17,122
|
|
|
$
|
25,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 38 percent
comprised of the effective rates in each taxing jurisdiction. |
Hedge
Ineffectiveness
Unrealized margins recorded in our natural gas marketing and
pipeline, storage and other segments are comprised of various
components, including, but not limited to, unrealized gains and
losses arising from hedge ineffectiveness. Our hedge
ineffectiveness primarily results from differences in the
location and timing of the derivative instrument and the hedged
item and could materially affect our results of operations for
the reported period. Although these unrealized gains and losses
are currently recorded in our income statement, they are not
indicative of the economic gross profit we anticipate realizing
when the underlying physical and financial transactions are
settled.
Fair value and cash flow hedge ineffectiveness arising from
natural gas market price differences between the locations of
the hedged inventory and the delivery location specified in the
hedge instruments is referred to as basis ineffectiveness.
Ineffectiveness arising from changes in the fair value of the
fair value hedges 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 are referred to
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
as timing ineffectiveness. The portion of our unrealized margins
related to basis and timing ineffectiveness gains and losses for
the three and nine months ended June 30, 2008 and 2007 are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Basis ineffectiveness:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value basis ineffectiveness
|
|
$
|
(2,402
|
)
|
|
$
|
1,073
|
|
|
$
|
(1,185
|
)
|
|
$
|
942
|
|
Cash flow basis ineffectiveness
|
|
|
(406
|
)
|
|
|
1,479
|
|
|
|
(281
|
)
|
|
|
710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total basis ineffectiveness
|
|
|
(2,808
|
)
|
|
|
2,552
|
|
|
|
(1,466
|
)
|
|
|
1,652
|
|
Timing ineffectiveness:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value timing ineffectiveness
|
|
|
(1,842
|
)
|
|
|
(1,759
|
)
|
|
|
42,040
|
|
|
|
80,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total hedge ineffectiveness
|
|
$
|
(4,650
|
)
|
|
$
|
793
|
|
|
$
|
40,574
|
|
|
$
|
82,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
Long-term debt at June 30, 2008 and September 30, 2007
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Unsecured 4.00% Senior Notes, due October 2009
|
|
$
|
400,000
|
|
|
$
|
400,000
|
|
Unsecured 7.375% Senior Notes, due 2011
|
|
|
350,000
|
|
|
|
350,000
|
|
Unsecured 10% Notes, due 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 5.95% Senior Notes, due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A,
1995-2,
6.27%, due 2010
|
|
|
10,000
|
|
|
|
10,000
|
|
Series A,
1995-1,
6.67%, due 2025
|
|
|
10,000
|
|
|
|
10,000
|
|
Unsecured 6.75% Debentures, due 2028
|
|
|
150,000
|
|
|
|
150,000
|
|
First Mortgage Bonds
|
|
|
|
|
|
|
|
|
Series P, 10.43% due May 2008
|
|
|
|
|
|
|
7,500
|
|
Other term notes due in installments through 2013
|
|
|
1,648
|
|
|
|
3,890
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,123,951
|
|
|
|
2,133,693
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(3,163
|
)
|
|
|
(3,547
|
)
|
Current maturities
|
|
|
(1,059
|
)
|
|
|
(3,831
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,119,729
|
|
|
$
|
2,126,315
|
|
|
|
|
|
|
|
|
|
|
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Short-term
debt
At June 30, 2008, there was $113.3 million outstanding
under our commercial paper program and bank credit facilities.
At September 30, 2007, there was $150.6 million
outstanding under our commercial paper program and bank credit
facilities.
Shelf
Registration
On December 4, 2006, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in new common stock
and/or debt
securities available for issuance. As of June 30, 2008, we
had approximately $450 million of availability remaining
under the registration statement. Due to certain restrictions
placed by one state regulatory commission on our ability to
issue securities under the registration statement, we are
permitted to issue a total of approximately $100 million of
equity securities, $50 million of senior debt securities
and $300 million of subordinated debt securities. In
addition, due to restrictions imposed by another state
regulatory commission, if the credit ratings on our senior
unsecured debt were to fall below investment grade from either
Standard & Poors Corporation (BBB-),
Moodys Investors Services, Inc. (Baa3) or Fitch Ratings,
Ltd. (BBB-), our ability to issue any type of debt securities
under the registration statement would be suspended until we
received an investment grade rating from all of the three credit
rating agencies.
Credit
facilities
We maintain both committed and uncommitted credit facilities.
Borrowings under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas and the
increased gas supplies required to meet customers needs
during periods of cold weather.
Committed
credit facilities
As of June 30, 2008, we had three short-term committed
revolving credit facilities totaling $918 million. The
first facility is a five-year unsecured facility, expiring
December 2011, for $600 million that bears interest at a
base rate or at the LIBOR rate for the applicable interest
period, plus from 0.30 percent to 0.75 percent, based
on the Companys credit ratings, and serves as a backup
liquidity facility for our $600 million commercial paper
program. At June 30, 2008, there was $113.3 million
outstanding under our commercial paper program.
The second facility is a $300 million unsecured
364-day
facility expiring November 2008, that bears interest at a base
rate or the LIBOR rate for the applicable interest period, plus
from 0.30 percent to 0.75 percent, based on the
Companys credit ratings. At June 30, 2008, there were
no borrowings under this facility.
The third facility is an $18 million unsecured facility
that bears interest at a daily negotiated rate, generally based
on the Federal Funds rate plus a variable margin. This facility
expired on March 31, 2008 and was renewed effective
April 1, 2008 for one year with no material changes to the
terms and pricing. At June 30, 2008, there were no
borrowings under this facility.
The availability of funds under our 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 our revolving
credit 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 June 30, 2008, our
15
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
total-debt-to-total-capitalization
ratio, as defined, was 55 percent. In addition, both the
interest margin over the Eurodollar rate and the fee that we pay
on unused amounts under our revolving credit facilities are
subject to adjustment depending upon our credit ratings. The
revolving credit facilities each contain the same limitation
with respect to our total-debt-to-total-capitalization ratio.
Uncommitted
credit facilities
AEM has a $580 million uncommitted demand working capital
credit facility. On March 31, 2008, AEM and the
participating banks amended the facility, primarily to extend it
to March 31, 2009. In addition, the amendment removed the
financial covenant relating to the amount of cumulative losses
that could be incurred by AEM and its subsidiaries over a
specific period of time and included provisions permitting the
participating banks, or their affiliates, to participate in
physical commodity transactions with AEM.
Borrowings under the credit facility can be made either as
revolving loans or offshore rate loans. Revolving loan
borrowings will bear interest at a floating rate equal to a base
rate defined as the higher of (i) 0.50 percent per
annum above the Federal Funds rate or (ii) the
lenders prime rate plus 0.25 percent. Offshore rate
loan borrowings will bear interest at a floating rate equal to a
base rate based upon LIBOR for the applicable interest period
plus an applicable margin, ranging from 1.25 percent to
1.625 percent per annum, depending on the excess
tangible net worth of AEM, as defined in the credit facility.
Borrowings drawn down under letters of credit issued by the
banks will bear interest at a floating rate equal to the base
rate, as defined above, plus an applicable margin, which will
range from 1.00 percent to 1.875 percent per annum,
depending on the excess tangible net worth of AEM and whether
the letters of credit are swap-related standby letters of credit.
AEM is required by the financial covenants in the credit
facility not to exceed a maximum ratio of total liabilities to
tangible net worth of 5 to 1. At June 30, 2008, AEMs
ratio of total liabilities to tangible net worth, as defined,
was 1.97 to 1. Additionally, AEM must maintain minimum levels of
net working capital ranging from $20 million to
$120 million and a minimum tangible net worth ranging from
$21 million to $121 million. As defined in the
financial covenants, at June 30, 2008, AEMs net
working capital was $253.3 million and its tangible net
worth was $256.5 million.
At June 30, 2008, there were no borrowings outstanding
under this credit facility. However, at June 30, 2008, AEM
letters of credit totaling $161.9 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 $88.1 million at June 30, 2008. This line of
credit is collateralized by substantially all of the assets of
AEM and is guaranteed by AEH.
The Company also had an unsecured short-term uncommitted credit
line of $25 million that is used for working-capital and
letter-of-credit purposes. In January 2008, the unused portion
of this facility was terminated by the lending bank and the
remaining balance will be terminated as the outstanding letters
of credit expire. At June 30, 2008, there was
$5.3 million in letters of credit outstanding under this
facility.
The Company has a $200 million intercompany uncommitted
revolving credit facility with AEH. This facility bears interest
at the lesser of (i) the one-month LIBOR rate plus
0.20 percent or (ii) the marginal borrowing rate
available to the Company on any such date under its commercial
paper program. Applicable state regulatory commissions have
approved this facility through December 31, 2008. At
June 30, 2008, there were no borrowings outstanding under
this facility.
AEH has a $200 million intercompany uncommitted demand
credit facility with the Company, which bears interest at the
rate of AEMs $580 million uncommitted demand working
capital credit facility plus 0.75 percent. Applicable state
regulatory commissions have approved this facility through
December 31, 2008. At June 30, 2008, there was
$17.3 million outstanding under this facility.
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In addition, to supplement its $580 million credit
facility, AEM has a $200 million intercompany uncommitted
demand credit facility with AEH, which bears interest at the
rate of AEMs $580 million uncommitted demand working
capital credit facility plus 0.75 percent. Any outstanding
amounts under this facility are subordinated to AEMs
$580 million uncommitted demand credit facility. At
June 30, 2008, there was $41.0 million outstanding
under this facility.
Debt
Covenants
We had other covenants in addition to those described above. Our
Series P First Mortgage Bonds contained provisions that
allowed us to prepay the outstanding balance in whole at any
time, subject to a prepayment premium. The First Mortgage Bonds
provided for certain cash flow requirements and restrictions on
additional indebtedness, sale of assets and payment of
dividends. In May 2008, we redeemed our Series P First
Mortgage Bonds which were scheduled to mature in November 2013.
Since the bonds have been redeemed, the debt covenants described
above no longer apply.
We were in compliance with all of our debt covenants as of
June 30, 2008. If we were unable to comply with our debt
covenants, we could be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions. Our public debt indentures relating to our
senior notes and debentures, as well as our revolving credit
agreements, each contain a default provision that is triggered
if outstanding indebtedness arising out of any other credit
agreements in amounts ranging from in excess of $15 million
to in excess of $100 million becomes due by acceleration or
is not paid at maturity. In addition, 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. Additionally, this
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.
Except as described above, we have no 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.
Public
Offering
On December 13, 2006, we completed a public offering of
6,325,000 shares of our common stock including the
underwriters exercise of their overallotment option of
825,000 shares. The offering was priced at $31.50 and
generated net proceeds of approximately $192 million. We
used the net proceeds from this offering to reduce short-term
debt.
Shareholder
Rights Plan
In November 1997, our Board of Directors declared a dividend
distribution of one right for each outstanding share of our
common stock to shareholders of record at the close of business
on May 10, 1998, the description and terms of which were
set forth in a rights agreement between us and the rights agent
dated May 10, 1998. From that time until the expiration of
the rights agreement on May 10, 2008, when all rights
terminated, each share of common stock we issued included a
right that entitled the holder to purchase from us a one-tenth
share of our common stock at a purchase price of $8.00 per
share, subject to adjustment.
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Basic and diluted earnings (loss) per share for the three and
nine months ended June 30, 2008 and 2007 are calculated as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Net income (loss)
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per share
weighted average common shares
|
|
|
89,648
|
|
|
|
88,366
|
|
|
|
89,281
|
|
|
|
86,378
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
|
|
|
|
|
|
|
|
557
|
|
|
|
464
|
|
Stock options
|
|
|
|
|
|
|
|
|
|
|
99
|
|
|
|
169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per share
weighted average common shares
|
|
|
89,648
|
|
|
|
88,366
|
|
|
|
89,937
|
|
|
|
87,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share basic
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
2.00
|
|
|
$
|
2.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share diluted
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
1.99
|
|
|
$
|
2.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were approximately 557,000 and 466,000 restricted and
other shares and approximately 99,000 and 165,000 stock options
that were excluded from the calculation of diluted earnings per
share for the three months ended June 30, 2008 and 2007 as
their inclusion in the computation would be anti-dilutive.
There were no out-of-the-money options excluded from the
computation of diluted earnings per share for the three and nine
months ended June 30, 2008 and 2007 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 and nine
months ended June 30, 2008 and 2007 are presented in the
following table. All of these costs are recoverable through our
gas distribution rates; however, a portion of these costs is
capitalized into our gas distribution rate base. The remaining
costs are recorded as a component of operation and maintenance
expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,879
|
|
|
$
|
4,017
|
|
|
$
|
3,342
|
|
|
$
|
2,807
|
|
Interest cost
|
|
|
6,736
|
|
|
|
6,496
|
|
|
|
2,912
|
|
|
|
2,640
|
|
Expected return on assets
|
|
|
(6,311
|
)
|
|
|
(6,089
|
)
|
|
|
(715
|
)
|
|
|
(597
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
377
|
|
|
|
377
|
|
Amortization of prior service cost
|
|
|
(171
|
)
|
|
|
44
|
|
|
|
|
|
|
|
9
|
|
Amortization of actuarial loss
|
|
|
1,926
|
|
|
|
2,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
6,059
|
|
|
$
|
6,903
|
|
|
$
|
5,916
|
|
|
$
|
5,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
11,635
|
|
|
$
|
12,053
|
|
|
$
|
10,024
|
|
|
$
|
8,421
|
|
Interest cost
|
|
|
20,208
|
|
|
|
19,486
|
|
|
|
8,736
|
|
|
|
7,921
|
|
Expected return on assets
|
|
|
(18,932
|
)
|
|
|
(18,267
|
)
|
|
|
(2,145
|
)
|
|
|
(1,791
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
1,133
|
|
|
|
1,133
|
|
Amortization of prior service cost
|
|
|
(513
|
)
|
|
|
134
|
|
|
|
|
|
|
|
25
|
|
Amortization of actuarial loss
|
|
|
5,778
|
|
|
|
7,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
18,176
|
|
|
$
|
20,709
|
|
|
$
|
17,748
|
|
|
$
|
15,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three and nine months ended June 30, 2008 and 2007
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Discount rate
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
|
|
6.30
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
5.00
|
%
|
|
|
5.20
|
%
|
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. We are not required to contribute
to our pension plans during fiscal 2008 and do not anticipate
making contributions. However, we contributed $6.7 million
to our other post-retirement benefit plans during the nine
months ended June 30, 2008. We expect to contribute a total
of approximately $10 million to these plans during fiscal
2008.
|
|
8.
|
Commitments
and Contingencies
|
Litigation
and Environmental Matters
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. We have
responded timely to two sets of data requests received from the
Commission and are fully cooperating with the Commission during
this investigation.
Subsequent to responding to the second set of data requests, the
Commission agreed to allow the Company to conduct our own
internal investigation into compliance with the
Commissions rules, and we will provide the results of this
internal investigation to the Commission upon its completion. We
currently are unable to predict the final outcome of this
investigation or the potential impact it could have on our
financial position, results of operations or cash flows.
On May 29, 2008, the Texas Railroad Commission adopted a
rule effective September 1, 2008, which will be applicable
to all natural gas utility companies operating in Texas
concerning the replacement of compression couplings at pre-bent
gas meter risers. Compliance with this rule will require us to
expend significant amounts of capital. This will cause us to
redirect a greater portion of our capital budget towards
19
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
our Mid-Tex Division but these prudent and mandatory
expenditures should be recoverable through our rates in this
division. As a result, we anticipate no long-term adverse impact
on our financial position, results of operations or cash flows.
With respect to the specific litigation and
environmental-related matters or claims that were disclosed in
Note 13 to the financial statements in our Annual Report on
Form 10-K
for the year ended September 30, 2007, there were no
material changes in the status of such litigation and
environmental-related matters or claims during the nine months
ended June 30, 2008. 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.
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
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At June 30, 2008, AEM was committed to
purchase 76.5 Bcf within one year, 38.4 Bcf within one
to three years and 1.8 Bcf after three years under indexed
contracts. AEM is committed to purchase 1.3 Bcf within one
year and 0.1 Bcf within one to three years under fixed
price contracts with prices ranging from $7.68 to $14.37.
Purchases under these contracts totaled $842.1 million and
$567.9 million for the three months ended June 30,
2008 and 2007 and $2,274.4 million and
$1,551.3 million for the nine months ended June 30,
2008 and 2007.
Our natural gas distribution operations, other than the Mid-Tex
Division, maintain supply contracts with several vendors that
generally cover a period of up to one year. Commitments for
estimated base gas volumes are established under these contracts
on a monthly basis at contractually negotiated prices.
Commitments for incremental daily purchases are made as
necessary during the month in accordance with the terms of the
individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area, which obligate it to purchase specified volumes at market
prices. The estimated fiscal year commitments under these
contracts as of June 30, 2008 are as follows (in thousands):
|
|
|
|
|
2008
|
|
$
|
71,430
|
|
2009
|
|
|
632,496
|
|
2010
|
|
|
164,008
|
|
2011
|
|
|
14,066
|
|
2012
|
|
|
12,878
|
|
Thereafter
|
|
|
16,124
|
|
|
|
|
|
|
|
|
$
|
911,002
|
|
|
|
|
|
|
Regulatory
Matters
During the three months ended June 30, 2008, we concluded
rate cases we had filed in our Kansas and Mid-Tex service areas.
As of June 30, 2008, rate cases were in progress in our
Georgia and Virginia service areas, and we were working with the
intervenors to complete their review of the Mid-Tex
Divisions first Rate
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Review Mechanism filing made in April 2008. These regulatory
proceedings are discussed in further detail in
Managements Discussion and Analysis Recent
Ratemaking Developments.
|
|
9.
|
Concentration
of Credit Risk
|
Information regarding our concentration of credit risk is
disclosed in Note 15 to the financial statements in our
Annual Report on
Form 10-K
for the year ended September 30, 2007. During the nine
months ended June 30, 2008, there were no material changes
in our concentration of credit risk.
Atmos Energy Corporation and our subsidiaries are engaged
primarily in the regulated natural gas distribution,
transmission and storage businesses as well as certain other
nonregulated businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 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 distribution system.
Through our nonregulated businesses, we provide natural gas
management and marketing services to municipalities, other local
distribution companies and industrial customers primarily in the
Midwest and Southeast. Additionally, we provide natural gas
transportation and storage services to certain of our natural
gas distribution operations and to third parties.
We operate the Company through the following four segments:
|
|
|
|
|
the natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations,
|
|
|
|
the regulated transmission and storage segment, which includes
the regulated pipeline and storage operations of the Atmos
Pipeline Texas Division,
|
|
|
|
the natural gas marketing segment, which includes a variety of
nonregulated natural gas management services and
|
|
|
|
the pipeline, storage and other segment, which is comprised of
our nonregulated natural gas gathering, transmission and storage
services.
|
In our determination of reportable segments, we consider 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, 2007. We evaluate
performance based on net income or loss of the respective
operating units.
As described in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2007, we changed
the composition of our operating segments. Effective September
2007, all prior period segment information has been restated to
conform to our new segment presentation.
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income statements for the three and nine-month periods ended
June 30, 2008 and 2007 by segment are presented in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
676,418
|
|
|
$
|
27,321
|
|
|
$
|
933,931
|
|
|
$
|
1,475
|
|
|
$
|
|
|
|
$
|
1,639,145
|
|
Intersegment revenues
|
|
|
221
|
|
|
|
18,965
|
|
|
|
255,791
|
|
|
|
2,405
|
|
|
|
(277,382
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
676,639
|
|
|
|
46,286
|
|
|
|
1,189,722
|
|
|
|
3,880
|
|
|
|
(277,382
|
)
|
|
|
1,639,145
|
|
Purchased gas cost
|
|
|
476,711
|
|
|
|
|
|
|
|
1,192,353
|
|
|
|
706
|
|
|
|
(276,847
|
)
|
|
|
1,392,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
199,928
|
|
|
|
46,286
|
|
|
|
(2,631
|
)
|
|
|
3,174
|
|
|
|
(535
|
)
|
|
|
246,222
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
95,853
|
|
|
|
17,042
|
|
|
|
4,433
|
|
|
|
1,115
|
|
|
|
(621
|
)
|
|
|
117,822
|
|
Depreciation and amortization
|
|
|
44,737
|
|
|
|
4,860
|
|
|
|
381
|
|
|
|
378
|
|
|
|
|
|
|
|
50,356
|
|
Taxes, other than income
|
|
|
54,141
|
|
|
|
2,493
|
|
|
|
391
|
|
|
|
310
|
|
|
|
|
|
|
|
57,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
194,731
|
|
|
|
24,395
|
|
|
|
5,205
|
|
|
|
1,803
|
|
|
|
(621
|
)
|
|
|
225,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
5,197
|
|
|
|
21,891
|
|
|
|
(7,836
|
)
|
|
|
1,371
|
|
|
|
86
|
|
|
|
20,709
|
|
Miscellaneous income
|
|
|
3,508
|
|
|
|
550
|
|
|
|
377
|
|
|
|
2,273
|
|
|
|
(5,108
|
)
|
|
|
1,600
|
|
Interest charges
|
|
|
28,504
|
|
|
|
6,606
|
|
|
|
2,850
|
|
|
|
532
|
|
|
|
(5,022
|
)
|
|
|
33,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(19,799
|
)
|
|
|
15,835
|
|
|
|
(10,309
|
)
|
|
|
3,112
|
|
|
|
|
|
|
|
(11,161
|
)
|
Income tax expense (benefit)
|
|
|
(7,421
|
)
|
|
|
5,570
|
|
|
|
(3,995
|
)
|
|
|
1,273
|
|
|
|
|
|
|
|
(4,573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,378
|
)
|
|
$
|
10,265
|
|
|
$
|
(6,314
|
)
|
|
$
|
1,839
|
|
|
$
|
|
|
|
$
|
(6,588
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
92,856
|
|
|
$
|
18,252
|
|
|
$
|
132
|
|
|
$
|
2,916
|
|
|
$
|
|
|
|
$
|
114,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2007
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
548,104
|
|
|
$
|
20,694
|
|
|
$
|
649,633
|
|
|
$
|
(279
|
)
|
|
$
|
|
|
|
$
|
1,218,152
|
|
Intersegment revenues
|
|
|
147
|
|
|
|
16,013
|
|
|
|
204,534
|
|
|
|
2,352
|
|
|
|
(223,046
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
548,251
|
|
|
|
36,707
|
|
|
|
854,167
|
|
|
|
2,073
|
|
|
|
(223,046
|
)
|
|
|
1,218,152
|
|
Purchased gas cost
|
|
|
357,608
|
|
|
|
|
|
|
|
854,743
|
|
|
|
228
|
|
|
|
(222,443
|
)
|
|
|
990,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
190,643
|
|
|
|
36,707
|
|
|
|
(576
|
)
|
|
|
1,845
|
|
|
|
(603
|
)
|
|
|
228,016
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
93,623
|
|
|
|
14,139
|
|
|
|
6,854
|
|
|
|
1,214
|
|
|
|
(689
|
)
|
|
|
115,141
|
|
Depreciation and amortization
|
|
|
43,661
|
|
|
|
4,559
|
|
|
|
376
|
|
|
|
378
|
|
|
|
|
|
|
|
48,974
|
|
Taxes, other than income
|
|
|
50,005
|
|
|
|
2,288
|
|
|
|
295
|
|
|
|
293
|
|
|
|
|
|
|
|
52,881
|
|
Impairment of long-lived assets
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
190,578
|
|
|
|
20,986
|
|
|
|
7,525
|
|
|
|
1,885
|
|
|
|
(689
|
)
|
|
|
220,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
65
|
|
|
|
15,721
|
|
|
|
(8,101
|
)
|
|
|
(40
|
)
|
|
|
86
|
|
|
|
7,731
|
|
Miscellaneous income
|
|
|
2,232
|
|
|
|
620
|
|
|
|
1,578
|
|
|
|
3,992
|
|
|
|
(4,156
|
)
|
|
|
4,266
|
|
Interest charges
|
|
|
28,987
|
|
|
|
6,720
|
|
|
|
2,012
|
|
|
|
830
|
|
|
|
(4,070
|
)
|
|
|
34,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(26,690
|
)
|
|
|
9,621
|
|
|
|
(8,535
|
)
|
|
|
3,122
|
|
|
|
|
|
|
|
(22,482
|
)
|
Income tax expense (benefit)
|
|
|
(11,000
|
)
|
|
|
3,459
|
|
|
|
(2,925
|
)
|
|
|
1,344
|
|
|
|
|
|
|
|
(9,122
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(15,690
|
)
|
|
$
|
6,162
|
|
|
$
|
(5,610
|
)
|
|
$
|
1,778
|
|
|
$
|
|
|
|
$
|
(13,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
78,829
|
|
|
$
|
10,761
|
|
|
$
|
187
|
|
|
$
|
454
|
|
|
$
|
|
|
|
$
|
90,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Operating revenues from external parties
|
|
$
|
3,126,083
|
|
|
$
|
72,588
|
|
|
$
|
2,568,643
|
|
|
$
|
13,326
|
|
|
$
|
|
|
|
$
|
5,780,640
|
|
Intersegment revenues
|
|
|
589
|
|
|
|
70,184
|
|
|
|
590,449
|
|
|
|
7,303
|
|
|
|
(668,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,126,672
|
|
|
|
142,772
|
|
|
|
3,159,092
|
|
|
|
20,629
|
|
|
|
(668,525
|
)
|
|
|
5,780,640
|
|
Purchased gas cost
|
|
|
2,296,020
|
|
|
|
|
|
|
|
3,099,428
|
|
|
|
1,773
|
|
|
|
(666,835
|
)
|
|
|
4,730,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
830,652
|
|
|
|
142,772
|
|
|
|
59,664
|
|
|
|
18,856
|
|
|
|
(1,690
|
)
|
|
|
1,050,254
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
291,678
|
|
|
|
47,560
|
|
|
|
17,835
|
|
|
|
3,939
|
|
|
|
(1,948
|
)
|
|
|
359,064
|
|
Depreciation and amortization
|
|
|
130,699
|
|
|
|
14,683
|
|
|
|
1,142
|
|
|
|
1,135
|
|
|
|
|
|
|
|
147,659
|
|
Taxes, other than income
|
|
|
142,063
|
|
|
|
6,322
|
|
|
|
3,798
|
|
|
|
987
|
|
|
|
|
|
|
|
153,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
564,440
|
|
|
|
68,565
|
|
|
|
22,775
|
|
|
|
6,061
|
|
|
|
(1,948
|
)
|
|
|
659,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
266,212
|
|
|
|
74,207
|
|
|
|
36,889
|
|
|
|
12,795
|
|
|
|
258
|
|
|
|
390,361
|
|
Miscellaneous income
|
|
|
7,654
|
|
|
|
933
|
|
|
|
1,775
|
|
|
|
6,243
|
|
|
|
(13,631
|
)
|
|
|
2,974
|
|
Interest charges
|
|
|
88,802
|
|
|
|
20,453
|
|
|
|
6,166
|
|
|
|
1,755
|
|
|
|
(13,373
|
)
|
|
|
103,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
185,064
|
|
|
|
54,687
|
|
|
|
32,498
|
|
|
|
17,283
|
|
|
|
|
|
|
|
289,532
|
|
Income tax expense
|
|
|
71,622
|
|
|
|
19,351
|
|
|
|
12,933
|
|
|
|
6,877
|
|
|
|
|
|
|
|
110,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
113,442
|
|
|
$
|
35,336
|
|
|
$
|
19,565
|
|
|
$
|
10,406
|
|
|
$
|
|
|
|
$
|
178,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
266,840
|
|
|
$
|
40,334
|
|
|
$
|
201
|
|
|
$
|
5,503
|
|
|
$
|
|
|
|
$
|
312,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2007
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Operating revenues from external parties
|
|
$
|
2,973,048
|
|
|
$
|
59,029
|
|
|
$
|
1,844,271
|
|
|
$
|
20,019
|
|
|
$
|
|
|
|
$
|
4,896,367
|
|
Intersegment revenues
|
|
|
480
|
|
|
|
63,618
|
|
|
|
516,631
|
|
|
|
7,464
|
|
|
|
(588,193
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,973,528
|
|
|
|
122,647
|
|
|
|
2,360,902
|
|
|
|
27,483
|
|
|
|
(588,193
|
)
|
|
|
4,896,367
|
|
Purchased gas cost
|
|
|
2,174,071
|
|
|
|
|
|
|
|
2,275,291
|
|
|
|
682
|
|
|
|
(585,971
|
)
|
|
|
3,864,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
799,457
|
|
|
|
122,647
|
|
|
|
85,611
|
|
|
|
26,801
|
|
|
|
(2,222
|
)
|
|
|
1,032,294
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
284,064
|
|
|
|
37,594
|
|
|
|
19,022
|
|
|
|
4,173
|
|
|
|
(2,480
|
)
|
|
|
342,373
|
|
Depreciation and amortization
|
|
|
133,287
|
|
|
|
13,400
|
|
|
|
1,153
|
|
|
|
1,195
|
|
|
|
|
|
|
|
149,035
|
|
Taxes, other than income
|
|
|
141,292
|
|
|
|
6,584
|
|
|
|
951
|
|
|
|
867
|
|
|
|
|
|
|
|
149,694
|
|
Impairment of long-lived assets
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
561,932
|
|
|
|
57,578
|
|
|
|
21,126
|
|
|
|
6,235
|
|
|
|
(2,480
|
)
|
|
|
644,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
237,525
|
|
|
|
65,069
|
|
|
|
64,485
|
|
|
|
20,566
|
|
|
|
258
|
|
|
|
387,903
|
|
Miscellaneous income
|
|
|
6,633
|
|
|
|
1,530
|
|
|
|
5,816
|
|
|
|
5,588
|
|
|
|
(11,884
|
)
|
|
|
7,683
|
|
Interest charges
|
|
|
91,164
|
|
|
|
20,852
|
|
|
|
3,418
|
|
|
|
5,465
|
|
|
|
(11,626
|
)
|
|
|
109,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
152,994
|
|
|
|
45,747
|
|
|
|
66,883
|
|
|
|
20,689
|
|
|
|
|
|
|
|
286,313
|
|
Income tax expense
|
|
|
60,530
|
|
|
|
16,661
|
|
|
|
26,515
|
|
|
|
8,201
|
|
|
|
|
|
|
|
111,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
92,464
|
|
|
$
|
29,086
|
|
|
$
|
40,368
|
|
|
$
|
12,488
|
|
|
$
|
|
|
|
$
|
174,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
222,526
|
|
|
$
|
37,142
|
|
|
$
|
837
|
|
|
$
|
2,518
|
|
|
$
|
|
|
|
$
|
263,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at June 30, 2008 and
September 30, 2007 by segment is presented in the following
tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,398,317
|
|
|
$
|
556,196
|
|
|
$
|
7,546
|
|
|
$
|
50,829
|
|
|
$
|
|
|
|
$
|
4,012,888
|
|
Investment in subsidiaries
|
|
|
476,542
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(474,446
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
32,949
|
|
|
|
|
|
|
|
13,308
|
|
|
|
244
|
|
|
|
|
|
|
|
46,501
|
|
Cash held on deposit in margin account
|
|
|
|
|
|
|
|
|
|
|
62,152
|
|
|
|
|
|
|
|
|
|
|
|
62,152
|
|
Assets from risk management activities
|
|
|
37,366
|
|
|
|
|
|
|
|
19,770
|
|
|
|
147
|
|
|
|
(14,383
|
)
|
|
|
42,900
|
|
Other current assets
|
|
|
687,453
|
|
|
|
16,669
|
|
|
|
627,786
|
|
|
|
49,919
|
|
|
|
(136,422
|
)
|
|
|
1,245,405
|
|
Intercompany receivables
|
|
|
490,979
|
|
|
|
|
|
|
|
|
|
|
|
203,115
|
|
|
|
(694,094
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,248,747
|
|
|
|
16,669
|
|
|
|
723,016
|
|
|
|
253,425
|
|
|
|
(844,899
|
)
|
|
|
1,396,958
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
2,245
|
|
|
|
|
|
|
|
|
|
|
|
2,245
|
|
Goodwill
|
|
|
567,775
|
|
|
|
132,490
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
734,976
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
5,904
|
|
|
|
|
|
|
|
|
|
|
|
5,904
|
|
Deferred charges and other assets
|
|
|
203,663
|
|
|
|
9,477
|
|
|
|
1,228
|
|
|
|
17,451
|
|
|
|
|
|
|
|
231,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,895,044
|
|
|
$
|
714,832
|
|
|
$
|
762,125
|
|
|
$
|
332,134
|
|
|
$
|
(1,319,345
|
)
|
|
$
|
6,384,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,105,407
|
|
|
$
|
124,055
|
|
|
$
|
155,832
|
|
|
$
|
196,655
|
|
|
$
|
(476,542
|
)
|
|
$
|
2,105,407
|
|
Long-term debt
|
|
|
2,119,140
|
|
|
|
|
|
|
|
|
|
|
|
589
|
|
|
|
|
|
|
|
2,119,729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,224,547
|
|
|
|
124,055
|
|
|
|
155,832
|
|
|
|
197,244
|
|
|
|
(476,542
|
)
|
|
|
4,225,136
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of
long-term
debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,059
|
|
|
|
|
|
|
|
1,059
|
|
Short-term debt
|
|
|
113,257
|
|
|
|
|
|
|
|
41,000
|
|
|
|
17,275
|
|
|
|
(58,275
|
)
|
|
|
113,257
|
|
Liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
50,822
|
|
|
|
14,247
|
|
|
|
(14,383
|
)
|
|
|
50,686
|
|
Other current liabilities
|
|
|
635,200
|
|
|
|
6,078
|
|
|
|
343,238
|
|
|
|
95,290
|
|
|
|
(76,051
|
)
|
|
|
1,003,755
|
|
Intercompany payables
|
|
|
|
|
|
|
536,235
|
|
|
|
157,859
|
|
|
|
|
|
|
|
(694,094
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
748,457
|
|
|
|
542,313
|
|
|
|
592,919
|
|
|
|
127,871
|
|
|
|
(842,803
|
)
|
|
|
1,168,757
|
|
Deferred income taxes
|
|
|
393,426
|
|
|
|
44,710
|
|
|
|
8,948
|
|
|
|
3,585
|
|
|
|
|
|
|
|
450,669
|
|
Noncurrent liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
3,724
|
|
|
|
|
|
|
|
|
|
|
|
3,724
|
|
Regulatory cost of removal obligation
|
|
|
280,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
280,108
|
|
Deferred credits and other liabilities
|
|
|
248,506
|
|
|
|
3,754
|
|
|
|
702
|
|
|
|
3,434
|
|
|
|
|
|
|
|
256,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,895,044
|
|
|
$
|
714,832
|
|
|
$
|
762,125
|
|
|
$
|
332,134
|
|
|
$
|
(1,319,345
|
)
|
|
$
|
6,384,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2007
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,251,144
|
|
|
$
|
531,921
|
|
|
$
|
7,850
|
|
|
$
|
45,921
|
|
|
$
|
|
|
|
$
|
3,836,836
|
|
Investment in subsidiaries
|
|
|
396,474
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(394,378
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
28,881
|
|
|
|
|
|
|
|
31,703
|
|
|
|
141
|
|
|
|
|
|
|
|
60,725
|
|
Cash held on deposit in margin account
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
26,783
|
|
|
|
12,947
|
|
|
|
(17,881
|
)
|
|
|
21,849
|
|
Other current assets
|
|
|
643,353
|
|
|
|
20,065
|
|
|
|
337,169
|
|
|
|
76,731
|
|
|
|
(90,997
|
)
|
|
|
986,321
|
|
Intercompany receivables
|
|
|
536,985
|
|
|
|
|
|
|
|
|
|
|
|
114,300
|
|
|
|
(651,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,209,219
|
|
|
|
20,065
|
|
|
|
395,655
|
|
|
|
204,119
|
|
|
|
(760,163
|
)
|
|
|
1,068,895
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
2,716
|
|
Goodwill
|
|
|
567,775
|
|
|
|
132,490
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
734,976
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
5,535
|
|
|
|
|
|
|
|
|
|
|
|
5,535
|
|
Deferred charges and other assets
|
|
|
227,869
|
|
|
|
4,898
|
|
|
|
1,279
|
|
|
|
13,913
|
|
|
|
|
|
|
|
247,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,652,481
|
|
|
$
|
689,374
|
|
|
$
|
435,221
|
|
|
$
|
274,382
|
|
|
$
|
(1,154,541
|
)
|
|
$
|
5,896,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
1,965,754
|
|
|
$
|
88,719
|
|
|
$
|
107,090
|
|
|
$
|
200,665
|
|
|
$
|
(396,474
|
)
|
|
$
|
1,965,754
|
|
Long-term debt
|
|
|
2,125,007
|
|
|
|
|
|
|
|
|
|
|
|
1,308
|
|
|
|
|
|
|
|
2,126,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,090,761
|
|
|
|
88,719
|
|
|
|
107,090
|
|
|
|
201,973
|
|
|
|
(396,474
|
)
|
|
|
4,092,069
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of
long-term
debt
|
|
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
2,581
|
|
|
|
|
|
|
|
3,831
|
|
Short-term debt
|
|
|
187,284
|
|
|
|
|
|
|
|
30,000
|
|
|
|
|
|
|
|
(66,685
|
)
|
|
|
150,599
|
|
Liabilities from risk management activities
|
|
|
21,053
|
|
|
|
|
|
|
|
18,167
|
|
|
|
|
|
|
|
(17,881
|
)
|
|
|
21,339
|
|
Other current liabilities
|
|
|
519,642
|
|
|
|
6,394
|
|
|
|
186,792
|
|
|
|
53,297
|
|
|
|
(22,216
|
)
|
|
|
743,909
|
|
Intercompany payables
|
|
|
|
|
|
|
550,184
|
|
|
|
101,101
|
|
|
|
|
|
|
|
(651,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
729,229
|
|
|
|
556,578
|
|
|
|
336,060
|
|
|
|
55,878
|
|
|
|
(758,067
|
)
|
|
|
919,678
|
|
Deferred income taxes
|
|
|
326,518
|
|
|
|
40,565
|
|
|
|
(8,925
|
)
|
|
|
12,411
|
|
|
|
|
|
|
|
370,569
|
|
Noncurrent liabilities from risk management activities
|
|
|
|
|
|
|
|
|
|
|
290
|
|
|
|
|
|
|
|
|
|
|
|
290
|
|
Regulatory cost of removal obligation
|
|
|
271,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
271,059
|
|
Deferred credits and other liabilities
|
|
|
234,914
|
|
|
|
3,512
|
|
|
|
706
|
|
|
|
4,120
|
|
|
|
|
|
|
|
243,252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,652,481
|
|
|
$
|
689,374
|
|
|
$
|
435,221
|
|
|
$
|
274,382
|
|
|
$
|
(1,154,541
|
)
|
|
$
|
5,896,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of June 30, 2008, and the
related condensed consolidated statements of income for the
three-month and nine-month periods ended June 30, 2008 and
2007, and the condensed consolidated statements of cash flows
for the nine-month periods ended June 30, 2008 and 2007.
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, 2007, 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 27, 2007, 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, 2007, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
/s/ Ernst &
Young LLP
Dallas, Texas
August 5, 2008
28
|
|
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, 2007.
Cautionary
Statement for the Purposes of the Safe Harbor under the Private
Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on
Form 10-Q
may contain forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical fact included in
this Report are forward-looking statements made in good faith by
us and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation
Reform Act of 1995. When used in this Report, or any other of
our documents or oral presentations, the words
anticipate, believe,
estimate, expect, forecast,
goal, intend, objective,
plan, projection, seek,
strategy or similar words are intended to identify
forward-looking statements. Such forward-looking statements are
subject to risks and uncertainties that could cause actual
results to differ materially from those expressed or implied in
the statements relating to our strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties, which are
discussed in more detail in our Annual Report on
Form 10-K
for the year ended September 30, 2007, include the
following: regulatory trends and decisions, including
deregulation initiatives and the impact of rate proceedings
before various state regulatory commissions; market risks beyond
our control affecting our risk management activities including
market liquidity, commodity price volatility, increasing
interest rates and counterparty creditworthiness; the
concentration of our distribution, pipeline and storage
operations in one state; adverse weather conditions; our ability
to continue to access the capital markets; the effects of
inflation and changes in the availability and prices of natural
gas, including the volatility of natural gas prices; the
capital-intensive nature of our distribution business, increased
competition from energy suppliers and alternative forms of
energy; increased costs of providing pension and postretirement
health care benefits; the impact of environmental regulations on
our business; the inherent hazards and risks involved in
operating our distribution business, natural disasters,
terrorist activities or other events; and other uncertainties,
which may be discussed herein, including the outcome of any
pending federal or state regulatory investigations, 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 Corporation and our subsidiaries are engaged
primarily in the regulated natural gas distribution and
transportation and storage businesses as well as other
nonregulated natural gas businesses. We distribute natural gas
through sales and transportation arrangements to approximately
3.2 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 distribution system.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local gas distribution companies and industrial customers
primarily in the Midwest and Southeast and natural gas
transportation and storage services to certain of our natural
gas distribution divisions and to third parties.
29
We operate the Company through the following four segments:
|
|
|
|
|
the natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations,
|
|
|
|
the regulated transmission and storage segment, which includes
the regulated pipeline and storage operations of the Atmos
Pipeline Texas Division,
|
|
|
|
the natural gas marketing segment, which includes a variety of
nonregulated natural gas management services and
|
|
|
|
the pipeline, storage and other segment, which is comprised of
our nonregulated natural gas gathering, transmission and storage
services.
|
CRITICAL
ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in
accordance with accounting principles generally accepted in the
United States. Preparation of these financial statements
requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses
and the related disclosures of contingent assets and
liabilities. We based our estimates on historical experience and
various other assumptions that we believe to be reasonable under
the circumstances. On an ongoing basis, we evaluate our
estimates, including those related to risk management and
trading activities, 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 year ended September 30, 2007 and include the
following:
|
|
|
|
|
Regulation
|
|
|
|
Revenue Recognition
|
|
|
|
Allowance for Doubtful Accounts
|
|
|
|
Derivatives and Hedging Activities
|
|
|
|
Impairment Assessments
|
|
|
|
Pension and Other Postretirement Plans
|
Our critical accounting policies are reviewed by the Audit
Committee quarterly. There were no significant changes to these
critical accounting policies during the nine months ended
June 30, 2008.
30
RESULTS
OF OPERATIONS
The following table presents our consolidated financial
highlights for the three and nine months ended June 30,
2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
$
|
1,639,145
|
|
|
$
|
1,218,152
|
|
|
$
|
5,780,640
|
|
|
$
|
4,896,367
|
|
Gross profit
|
|
|
246,222
|
|
|
|
228,016
|
|
|
|
1,050,254
|
|
|
|
1,032,294
|
|
Operating expenses
|
|
|
225,513
|
|
|
|
220,285
|
|
|
|
659,893
|
|
|
|
644,391
|
|
Operating income
|
|
|
20,709
|
|
|
|
7,731
|
|
|
|
390,361
|
|
|
|
387,903
|
|
Miscellaneous income
|
|
|
1,600
|
|
|
|
4,266
|
|
|
|
2,974
|
|
|
|
7,683
|
|
Interest charges
|
|
|
33,470
|
|
|
|
34,479
|
|
|
|
103,803
|
|
|
|
109,273
|
|
Income (loss) before income taxes
|
|
|
(11,161
|
)
|
|
|
(22,482
|
)
|
|
|
289,532
|
|
|
|
286,313
|
|
Income tax expense (benefit)
|
|
|
(4,573
|
)
|
|
|
(9,122
|
)
|
|
|
110,783
|
|
|
|
111,907
|
|
Net income (loss)
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
Diluted net income (loss) per share
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
1.99
|
|
|
$
|
2.00
|
|
Our consolidated net income (loss) during the three and nine
months ended June 30, 2008 and 2007 was earned in each of
our business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
(12,378
|
)
|
|
$
|
(15,690
|
)
|
|
$
|
3,312
|
|
Regulated transmission and storage segment
|
|
|
10,265
|
|
|
|
6,162
|
|
|
|
4,103
|
|
Natural gas marketing segment
|
|
|
(6,314
|
)
|
|
|
(5,610
|
)
|
|
|
(704
|
)
|
Pipeline, storage and other segment
|
|
|
1,839
|
|
|
|
1,778
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
$
|
6,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
113,442
|
|
|
$
|
92,464
|
|
|
$
|
20,978
|
|
Regulated transmission and storage segment
|
|
|
35,336
|
|
|
|
29,086
|
|
|
|
6,250
|
|
Natural gas marketing segment
|
|
|
19,565
|
|
|
|
40,368
|
|
|
|
(20,803
|
)
|
Pipeline, storage and other segment
|
|
|
10,406
|
|
|
|
12,488
|
|
|
|
(2,082
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
|
$
|
4,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
The following tables segregate our consolidated net income
(loss) and diluted earnings per share between our regulated and
nonregulated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
(2,113
|
)
|
|
$
|
(9,528
|
)
|
|
$
|
7,415
|
|
Nonregulated operations
|
|
|
(4,475
|
)
|
|
|
(3,832
|
)
|
|
|
(643
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net loss
|
|
$
|
(6,588
|
)
|
|
$
|
(13,360
|
)
|
|
$
|
6,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
(0.02
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
0.09
|
|
Diluted EPS from nonregulated operations
|
|
|
(0.05
|
)
|
|
|
(0.04
|
)
|
|
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
(0.07
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
148,778
|
|
|
$
|
121,550
|
|
|
$
|
27,228
|
|
Nonregulated operations
|
|
|
29,971
|
|
|
|
52,856
|
|
|
|
(22,885
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
178,749
|
|
|
$
|
174,406
|
|
|
$
|
4,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.66
|
|
|
$
|
1.39
|
|
|
$
|
0.27
|
|
Diluted EPS from nonregulated operations
|
|
|
0.33
|
|
|
|
0.61
|
|
|
|
(0.28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
1.99
|
|
|
$
|
2.00
|
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following summarizes the results of our operations and other
significant events for the nine months ended June 30, 2008:
|
|
|
|
|
Regulated operations generated 83 percent of net income
during the nine months ended June 30, 2008 compared to
70 percent during the nine months ended June 30, 2007.
The $27.2 million increase in our regulated operations net
income primarily reflects rate increases in our Mid-Tex, Kansas,
Kentucky, Louisiana, Tennessee and West Texas service areas
coupled with higher rates and throughput in our Atmos
Pipeline Texas Division.
|
|
|
|
Nonregulated operations contributed 17 percent of net
income during the nine months ended June 30, 2008 compared
to 30 percent during the nine months ended June 30,
2007. The $22.9 million decrease in our nonregulated
operations net income primarily reflects lower asset
optimization margins partially offset by higher delivered gas
margins and higher unrealized gains.
|
|
|
|
For the nine months ended June 30, 2008, we generated
$417.4 million in operating cash flow compared with
$552.7 million for the nine months ended June 30,
2007, primarily reflecting an increase in cash required to
collateralize our risk management accounts.
|
|
|
|
In September 2007, we filed a statement of intent seeking a rate
increase of $51.9 million in our Mid-Tex Division. During
the fiscal 2008 second quarter, we reached a settlement
agreement with approximately 80 percent of the Mid-Tex
Divisions customers. In June 2008, the Railroad Commission
of Texas (RRC) issued a final order, which ended the case for
the remaining 20 percent of the Mid-Tex Divisions
customers.
|
32
Three
Months Ended June 30, 2008 compared with Three Months Ended
June 30, 2007
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
|
|
October May
|
Kansas
|
|
October May
|
Kentucky
|
|
November April
|
Louisiana
|
|
December March
|
Mississippi
|
|
November April
|
Tennessee
|
|
November April
|
Texas: Mid-Tex
|
|
November April
|
Texas: West Texas
|
|
October May
|
Virginia
|
|
January December
|
Our natural gas distribution operations are also affected by the
cost of natural gas. The cost of gas is passed through to our
customers without markup. Therefore, increases in the cost of
gas are offset by a corresponding increase in revenues.
Accordingly, we believe gross profit is a better indicator of
our financial performance than revenues. However, gross profit
in our Texas and Mississippi service areas include 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 revenue-related taxes arising from
changes in gas costs affect gross profit, over time the impact
is offset within operating income. Timing differences exist
between the recognition of revenue for franchise fees collected
from our customers and the recognition of expense of franchise
taxes. The effect of these timing differences can be significant
in periods of volatile gas prices, particularly in our Mid-Tex
Division. These timing differences may favorably or unfavorably
affect net income; however, these amounts should offset over
time with no permanent impact on net 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 June 30,
2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
199,928
|
|
|
$
|
190,643
|
|
|
$
|
9,285
|
|
Operating expenses
|
|
|
194,731
|
|
|
|
190,578
|
|
|
|
4,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,197
|
|
|
|
65
|
|
|
|
5,132
|
|
Miscellaneous income
|
|
|
3,508
|
|
|
|
2,232
|
|
|
|
1,276
|
|
Interest charges
|
|
|
28,504
|
|
|
|
28,987
|
|
|
|
(483
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(19,799
|
)
|
|
|
(26,690
|
)
|
|
|
6,891
|
|
Income tax benefit
|
|
|
(7,421
|
)
|
|
|
(11,000
|
)
|
|
|
3,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(12,378
|
)
|
|
$
|
(15,690
|
)
|
|
$
|
3,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
41,357
|
|
|
|
45,252
|
|
|
|
(3,895
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
32,126
|
|
|
|
29,311
|
|
|
|
2,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
73,483
|
|
|
|
74,563
|
|
|
|
(1,080
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.43
|
|
|
$
|
0.41
|
|
|
$
|
0.02
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
11.53
|
|
|
$
|
7.90
|
|
|
$
|
3.63
|
|
The following table shows our operating income by natural gas
distribution division for the three months ended June 30,
2008 and 2007. 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
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Colorado-Kansas
|
|
$
|
542
|
|
|
$
|
884
|
|
|
$
|
(342
|
)
|
Kentucky/Mid-States
|
|
|
5,757
|
|
|
|
1,762
|
|
|
|
3,995
|
|
Louisiana
|
|
|
5,086
|
|
|
|
5,921
|
|
|
|
(835
|
)
|
Mid-Tex
|
|
|
(3,043
|
)
|
|
|
(11,415
|
)
|
|
|
8,372
|
|
Mississippi
|
|
|
(946
|
)
|
|
|
2,115
|
|
|
|
(3,061
|
)
|
West Texas
|
|
|
(563
|
)
|
|
|
(391
|
)
|
|
|
(172
|
)
|
Other
|
|
|
(1,636
|
)
|
|
|
1,189
|
|
|
|
(2,825
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,197
|
|
|
$
|
65
|
|
|
$
|
5,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $9.3 million increase in natural gas distribution gross
profit primarily reflects an $8.9 million increase in
rates. The increase in rates primarily was attributable to the
Mid-Tex Division, which increased $5.0 million as a result
of the 2006 Gas Reliability Infrastructure Program (GRIP)
filing, the current year Mid-Tex rate case and the absence of a
one-time GRIP refund in the prior year. The current-year period
also reflects $3.9 million in rate increases in our Kansas,
Kentucky, Louisiana, Missouri, Tennessee and West Texas service
areas.
34
Gross profit also increased approximately $0.4 million in
revenue-related taxes primarily due to higher revenues, on which
the tax is calculated, in the current-year quarter compared to
the prior-year quarter. This increase, offset by a
$2.9 million quarter-over-quarter increase in the
associated franchise and state gross receipts tax expense
recorded as a component of taxes other than income, resulted in
a $2.5 million decrease in operating income when compared
with the prior-year quarter.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, increased
$4.2 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $2.3 million, primarily due to
an overall increase in administrative costs.
Depreciation and amortization expense increased
$1.1 million for the third quarter of fiscal 2008 compared
with third quarter of fiscal 2007. The increase primarily was
attributable to increases in assets placed in service during the
current year.
Operating expenses for the prior-year quarter also include a
$3.3 million noncash charge associated with the write-off
of software costs.
Interest charges allocated to the natural gas distribution
segment decreased $0.5 million due to lower average
effective interest rates experienced during the current-year
quarter compared to the prior-year quarter.
Recent
Ratemaking Developments
Significant ratemaking developments that occurred during the
nine months ended June 30, 2008 are discussed below. The
amounts described below represent the gross revenues that were
requested or received in each rate filing, which may not
necessarily reflect the increase in operating income obtained,
as certain operating costs may have increased as a result of a
commissions final ruling.
Mid-Tex
Division Rate Case
In September 2007, Atmos Energy filed a statement of intent
seeking a system-wide rate increase of $51.9 million in our
Mid-Tex Division. During the fiscal 2008 second quarter, we
reached a settlement with 438 of the 439 cities (the
Settlement Cities), which represent approximately
80 percent of the Mid-Tex Divisions customers. The
settlement agreement includes i) an annual system-wide rate
increase of approximately $10 million, of which
approximately $8 million related to the Settlement Cities;
ii) the ability to recover the gas cost portion of bad debt
expense, iii) a rate review mechanism (RRM) that will
adjust rates for the Settlement Cities annually to reflect
changes in the Mid-Tex Divisions cost of service and rate
base; iv) an authorized return on equity of
9.6 percent; v) an approved capital structure of
52 percent debt/48 percent equity and vi) the
establishment of a new program designed to encourage natural gas
conservation. New rates for the Settlement Cities were
implemented April 1, 2008.
In April 2008, the Mid-Tex Division filed its first RRM that
will adjust rates, effective October 1, 2008, for the
Settlement Cities only. The filing seeks an annual system-wide
rate increase of $33.5 million ($26.8 million for the
Settlement Cities) and is currently under review.
The City of Dallas and unincorporated areas, which represent the
remaining 20 percent of the Mid-Tex Divisions
customers, elected not to participate in the settlement
agreement. The Mid-Tex Division, the City of Dallas and
representatives for the unincorporated areas conducted a full
rate case before the Railroad Commission of Texas (RRC),
culminating in the issuance of a final order in June 2008. Key
terms of the final order include i) a $19.6 million
system-wide annual rate increase, of which approximately
$3.9 million related to the City of Dallas and
unincorporated areas, ii) the ability to recover the gas
cost portion of bad debt expense, iii) an authorized return
on equity of 10 percent; iv) an approved capital
structure of 52 percent
debt/48 percent
equity and v) the establishment of a new program designed
to encourage natural gas conservation. New rates for the City of
Dallas and the unincorporated areas were implemented in July
2008.
The final order did not include an RRM; therefore, we will
continue to make annual filings under the Texas Gas Reliability
Infrastructure Program (GRIP) in order to update rates for
customers in the City of
35
Dallas and in the unincorporated areas for approved capital
expenditures, and we will continue to file traditional rate
cases as necessary to assist in earning our authorized return in
these areas.
In May 2008, the Mid-Tex Division filed a system-wide 2007 GRIP
filing with the RRC. The filing seeks authorization to increase
annual rates, on a system-wide basis by $10.3 million based
on $58.2 million of capital costs incurred in 2007. It is
currently anticipated that the RRC will issue a final order in
this proceeding by November 2008. If approved as filed, the
filing should result in an annual rate increase of approximately
$2 million for customers in the City of Dallas and the
unincorporated areas.
Other
Rate Case Filings
In May 2006, Atmos Energy began receiving show cause
ordinances from several of the cities in the West Texas
Division. In December 2007, our West Texas Division reached a
settlement agreement with the West Texas cities, resulting in an
approved GRIP filing to include in rate base approximately
$7.0 million of capital costs incurred during calendar year
2006. The filing should result in additional annual revenues of
approximately $1.1 million.
In July 2008, the West Texas cities signed an agreement to
implement a rate review mechanism for our West Texas system. The
RRM will adjust rates on a periodic basis to reflect changes in
the West Texas Divisions cost of service and rate base for
this service area. The West Texas Division expects to file its
first RRM in September 2008, which will adjust rates for the
West Texas cities effective November 15, 2008.
In May 2008, the City of Lubbock approved its Conservation and
Customer Value Plan (CCVP), which contains an annual rate review
mechanism that would adjust rates to reflect changes in the West
Texas Divisions cost of service and rate base. The West
Texas Division filed its annual review filing under the CCVP in
June 2008, which is currently under review by the City of
Lubbock. The filing recommends a $0.5 million decrease in
annual rates, and is expected to become effective
October 1, 2008.
In October 2007, our Kentucky/Mid-States Division settled its
$11.1 million rate case filed in May 2007 with the
Tennessee Regulatory Authority. The settlement resulted in an
increase in annual revenues of $4.0 million and a
$4.1 million reduction in depreciation expense.
In September 2007, we filed an application with the Kansas
Corporation Commission (KCC) requesting a rate increase of
$5.0 million in our Kansas service area. A final order
adopting the Companys settlement with the KCC Staff was
issued in May 2008 resulting in an increase in annual revenues
of $2.1 million.
In February 2008, we filed for an annual rate increase of
$0.9 million in the Virginia jurisdiction of our
Kentucky/Mid-States Division. New rates, subject to refund, were
implemented in April 2008. A procedural schedule has been
established that should result in a final order being issued by
the fourth quarter of fiscal year 2008.
In March 2008, we filed for an annual rate increase of
$6.2 million in the Georgia jurisdiction of our
Kentucky/Mid-States Division. The first round of hearings was
completed in July 2008. A procedural schedule has been
established that should result in a final order being issued by
the fourth quarter of fiscal year 2008.
Stable
Rate Filings
Louisiana Division. In December 2007, we filed
our TransLa annual rate stabilization clause with the
Louisiana Public Service Commission requesting an increase of
$2.2 million, including an increase in depreciation expense
of approximately $0.4 million. The filing was for the test
year ended September 30, 2007. The TransLa filing was
approved in March 2008 and resulted in an increase of
$2.1 million in annual revenues effective April 1,
2008. In April 2008, we filed the LGS annual rate stabilization
clause, requesting an increase of $2.6 million. The filing
was for the test year ended December 31, 2007. The LGS
filing was approved in June 2008 and resulted in an increase of
$1.7 million in annual revenues effective July 1, 2008.
Mississippi Division. In December 2007, the
Mississippi Public Service Commission approved our annual stable
rate filing with no change in rates.
36
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.
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the three months ended
June 30, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
18,761
|
|
|
$
|
15,718
|
|
|
$
|
3,043
|
|
Third-party transportation
|
|
|
22,485
|
|
|
|
16,807
|
|
|
|
5,678
|
|
Storage and park and lend services
|
|
|
2,387
|
|
|
|
1,893
|
|
|
|
494
|
|
Other
|
|
|
2,653
|
|
|
|
2,289
|
|
|
|
364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
46,286
|
|
|
|
36,707
|
|
|
|
9,579
|
|
Operating expenses
|
|
|
24,395
|
|
|
|
20,986
|
|
|
|
3,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
21,891
|
|
|
|
15,721
|
|
|
|
6,170
|
|
Miscellaneous income
|
|
|
550
|
|
|
|
620
|
|
|
|
(70
|
)
|
Interest charges
|
|
|
6,606
|
|
|
|
6,720
|
|
|
|
(114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
15,835
|
|
|
|
9,621
|
|
|
|
6,214
|
|
Income tax expense
|
|
|
5,570
|
|
|
|
3,459
|
|
|
|
2,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
10,265
|
|
|
$
|
6,162
|
|
|
$
|
4,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
181,112
|
|
|
|
157,825
|
|
|
|
23,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
152,450
|
|
|
|
125,639
|
|
|
|
26,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $9.6 million increase in gross profit primarily was
attributable to a $4.4 million increase from rate
adjustments resulting from our 2006 and 2007 GRIP filings and a
$2.5 million increase from transportation volumes.
Consolidated throughput increased 21 percent, primarily due
to increased transportation in the Barnett Shale region of
Texas. The improvement in gross profit also reflects
$1.5 million of increased
per-unit
transportation margins due to favorable market conditions.
Operating expenses increased $3.4 million primarily due to
increased pipeline integrity and maintenance costs.
Recent
Ratemaking Developments
In April 2008, the RRC approved the GRIP filing for our Atmos
Pipeline Texas Division to include in rate base
approximately $46.6 million of capital costs incurred
during calendar year 2007. The filing should
37
result in additional annual revenues of approximately
$7.0 million. These revenues represent the gross revenues
that were received in the filing, which may not necessarily
result in an equal increase in operating income, as some
operating costs may increase.
Natural
Gas Marketing Segment
Our natural gas marketing activities are conducted through Atmos
Energy Marketing, LLC (AEM). AEM aggregates and purchases gas
supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request, 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, our revenues
arise from the types of commercial transactions we have
structured with our customers and include the value we extract
by optimizing the storage and transportation capacity we own or
control as well as revenues received for services we deliver.
Our asset optimization activities seek to maximize the economic
value associated with the storage and transportation capacity we
own or control. We attempt to meet this objective by engaging in
natural gas storage transactions in which we seek to find and
profit from the 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. We also seek to participate in transactions in which we
combine the natural gas commodity and transportation costs to
minimize our costs incurred to serve our customers by
identifying the lowest cost alternative within the natural gas
supplies, transportation and markets to which we have access.
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.
AEM continually manages its net physical position to attempt to
increase in the future the potential economic gross profit that
was created when the original transaction was executed.
Therefore, AEM may subsequently change its originally scheduled
storage injection and withdrawal plans from one time period to
another based on market conditions and recognize any associated
gains or losses at that time. If AEM elects to accelerate the
withdrawal of physical gas, it will execute new financial
instruments to hedge the original financial instruments. If AEM
elects to defer the withdrawal of gas, it will reset its
financial instruments by settling the original financial
instruments and executing new ones to correspond to the revised
withdrawal schedule.
We use financial instruments, designated as fair value hedges,
to hedge our natural gas inventory used in our natural gas
marketing storage activities. These financial instruments are
marked to market each month based upon the NYMEX price with
changes in fair value recognized as unrealized gains and losses
in the period of change. The hedged natural gas inventory is
marked to market at the end of each month based on the Gas Daily
index with changes in fair value recognized as unrealized gains
and losses in the period of change. Changes in the spreads
between the forward natural gas prices used to value the
financial hedges designated against our physical inventory and
the market (spot) prices used to value our physical storage
result in unrealized margins until the underlying physical gas
is withdrawn and the related financial instruments are settled.
Once the gas is withdrawn and the financial instruments are
settled, the previously unrealized margins associated with these
net positions are realized.
AEM also uses financial instruments to capture additional
storage arbitrage opportunities that may arise after the
execution of 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.
38
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the three months ended June 30, 2008
and 2007 are presented below. Gross profit margin consists
primarily of margins earned from the delivery of gas and related
services requested by our customers and margins earned from
asset optimization activities, which are derived from the
utilization of our proprietary and managed third-party storage
and transportation assets to capture favorable arbitrage spreads
through natural gas trading activities.
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 (spot) 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
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
11,231
|
|
|
$
|
9,999
|
|
|
$
|
1,232
|
|
Asset optimization
|
|
|
(37,551
|
)
|
|
|
(33,376
|
)
|
|
|
(4,175
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,320
|
)
|
|
|
(23,377
|
)
|
|
|
(2,943
|
)
|
Unrealized margins
|
|
|
23,689
|
|
|
|
22,801
|
|
|
|
888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
(2,631
|
)
|
|
|
(576
|
)
|
|
|
(2,055
|
)
|
Operating expenses
|
|
|
5,205
|
|
|
|
7,525
|
|
|
|
(2,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
(7,836
|
)
|
|
|
(8,101
|
)
|
|
|
265
|
|
Miscellaneous income
|
|
|
377
|
|
|
|
1,578
|
|
|
|
(1,201
|
)
|
Interest charges
|
|
|
2,850
|
|
|
|
2,012
|
|
|
|
838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(10,309
|
)
|
|
|
(8,535
|
)
|
|
|
(1,774
|
)
|
Income tax benefit
|
|
|
(3,995
|
)
|
|
|
(2,925
|
)
|
|
|
(1,070
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(6,314
|
)
|
|
$
|
(5,610
|
)
|
|
$
|
(704
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
103,403
|
|
|
|
104,783
|
|
|
|
(1,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
82,122
|
|
|
|
85,413
|
|
|
|
(3,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
17.5
|
|
|
|
21.5
|
|
|
|
(4.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $2.1 million decrease in our natural gas marketing
segments gross profit primarily reflects a
$4.2 million decrease in realized asset optimization
margins. Natural gas market conditions were significantly less
volatile during the current-year compared with the prior-year,
which created fewer opportunities to realize arbitrage gains.
During the quarter, AEM elected to defer storage withdrawals and
reset the corresponding financial instruments in order to
increase, in future periods, the potential gross profit it could
realize from its asset optimization activities. As a result, AEM
realized settlement losses without corresponding storage
withdrawal gains in the current quarter. In the prior year, AEM
accelerated the withdrawal of physical gas into the fiscal 2007
second quarter and executed new financial instruments to hedge
the original financial instruments. The losses incurred on the
settlement of these financial instruments in the prior-year
quarter were smaller than the settlement losses experienced in
the current quarter.
The increased loss generated from realized asset optimization
activities was partially offset by a $1.2 million increase
in realized delivered gas margins. The increase was largely
attributable to slightly higher
per-unit
margins, compared with the prior-year quarter, partially offset
by slightly lower sales volumes.
39
Gross profit margin was also favorably impacted by a
$0.9 million increase in unrealized margins attributable to
a narrowing of the spreads between current cash prices and
forward natural gas prices. The change in unrealized margins
also reflects the recognition of previously unrealized margins
as a component of realized margins as a result of injecting and
withdrawing gas and settling financial instruments as a part of
AEMs asset optimization activities.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income taxes,
decreased $2.3 million primarily due to a decrease in
employee and other administrative costs.
Economic
Gross Profit
AEM monitors the impact of its asset optimization efforts by
estimating the gross profit, before associated storage fees,
that it captured through the purchase and sale of physical
natural gas and the execution of the associated financial
instruments. This economic gross profit, combined with the
effect of the future reversal of unrealized gains or losses
currently recognized in the income statement is referred to as
the potential gross
profit.(1)
The following table presents AEMs economic gross profit
and its potential gross profit at June 30, 2008,
March 31, 2008, December 31, 2007 and
September 30, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated Net
|
|
|
|
|
|
|
Net Physical
|
|
|
Economic Gross
|
|
|
Unrealized Gain
|
|
|
Potential Gross
|
|
Period Ending
|
|
Position
|
|
|
Profit
|
|
|
(Loss)
|
|
|
Profit(1)
|
|
|
|
(Bcf)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
June 30, 2008
|
|
|
17.5
|
|
|
$
|
48.2
|
|
|
$
|
34.3
|
|
|
$
|
13.9
|
|
March 31, 2008
|
|
|
20.7
|
|
|
$
|
10.8
|
|
|
$
|
(0.6
|
)
|
|
$
|
11.4
|
|
December 31, 2007
|
|
|
17.7
|
|
|
$
|
44.2
|
|
|
$
|
32.9
|
|
|
$
|
11.3
|
|
September 30, 2007
|
|
|
12.3
|
|
|
$
|
40.8
|
|
|
$
|
10.8
|
|
|
$
|
30.0
|
|
|
|
|
(1) |
|
Potential gross profit represents the increase in AEMs
gross profit in future periods if its optimization efforts are
executed as planned. This amount does not include storage and
other operating expenses and increased 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 gross profit 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. |
As of June 30, 2008, based upon AEMs planned
inventory withdrawal schedule and associated planned settlement
of financial instruments, the economic gross profit was
$48.2 million. This amount will be reduced by
$34.3 million of net unrealized gains recorded in the
financial statements as of June 30, 2008 that will reverse
when the inventory is withdrawn and the accompanying financial
instruments are settled. Therefore, the potential gross profit
was $13.9 million at June 30, 2008.
The $2.5 million increase in potential gross profit as
compared to March 31, 2008, is comprised of a
$37.4 million increase in the economic gross profit,
principally due to the election to roll positions into forward
months as described above, partially offset by a $34.9 million
increase in unrealized gains primarily attributable to
recognizing as a component of realized margin previously
unrealized losses and a favorable movement in the market prices
used to value our natural gas storage inventory.
The economic gross profit is based upon planned storage
injection and withdrawal schedules and its realization is
contingent upon the execution of this plan, weather and other
execution factors. Since AEM actively manages and optimizes its
portfolio to attempt to enhance the future profitability of its
storage position, it may change its scheduled storage injection
and withdrawal plans from one time period to another based on
market conditions. Therefore, we cannot ensure that the economic
gross profit or the potential gross profit calculated as of
June 30, 2008 will be fully realized in the future nor can
we predict in what time
40
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. Assuming AEM fully executes its plan in place on
June 30, 2008, without encountering operational or other
issues, we anticipate a portion of the potential gross profit as
of June 30, 2008 will be recognized during the final
quarter of fiscal 2008 with most of the remainder recognized
during fiscal 2009.
Pipeline,
Storage and Other Segment
Our pipeline, storage and other segment primarily consists of
the operations of Atmos Pipeline and Storage, LLC (APS), Atmos
Energy Services, LLC (AES) and Atmos Power Systems, Inc., which
are each wholly-owned by Atmos Energy Holdings, Inc.
APS owns or has an interest in underground storage fields in
Kentucky and Louisiana. We use these storage facilities to
reduce the need to contract for additional pipeline capacity to
meet customer demand during peak periods. Additionally,
beginning in fiscal 2006, APS initiated activities in the
natural gas gathering business. As of June 30, 2008, these
activities were limited in nature.
AES, through December 31, 2006, provided natural gas
management services to our natural gas distribution operations,
other than the Mid-Tex Division. These services included
aggregating and purchasing gas supply, arranging transportation
and storage logistics and ultimately delivering the gas to our
natural gas distribution service areas at competitive prices.
Effective January 1, 2007, these services were moved to our
shared services function included in our natural gas
distribution segment. AES continues to provide limited services
to our natural gas distribution divisions, and the revenues AES
receives are equal to the costs incurred to provide those
services.
Through Atmos Power Systems, Inc., we have constructed electric
peaking power-generating plants and associated facilities and
lease these plants through lease agreements that are accounted
for as sales under generally accepted accounting principles.
Results for this segment are primarily impacted by seasonal
weather patterns and volatility in the natural gas markets.
Additionally, this segments results include an unrealized
component as APS hedges its risk associated with its asset
optimization activities.
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the three months ended June 30, 2008
and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Storage and transportation services
|
|
$
|
3,691
|
|
|
$
|
4,060
|
|
|
$
|
(369
|
)
|
Asset optimization
|
|
|
(1,329
|
)
|
|
|
(2,247
|
)
|
|
|
918
|
|
Other
|
|
|
1,210
|
|
|
|
845
|
|
|
|
365
|
|
Unrealized margins
|
|
|
(398
|
)
|
|
|
(813
|
)
|
|
|
415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
3,174
|
|
|
|
1,845
|
|
|
|
1,329
|
|
Operating expenses
|
|
|
1,803
|
|
|
|
1,885
|
|
|
|
(82
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
1,371
|
|
|
|
(40
|
)
|
|
|
1,411
|
|
Miscellaneous income
|
|
|
2,273
|
|
|
|
3,992
|
|
|
|
(1,719
|
)
|
Interest charges
|
|
|
532
|
|
|
|
830
|
|
|
|
(298
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
3,112
|
|
|
|
3,122
|
|
|
|
(10
|
)
|
Income tax expense
|
|
|
1,273
|
|
|
|
1,344
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,839
|
|
|
$
|
1,778
|
|
|
$
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
Pipeline, storage and other gross profit increased
$1.3 million primarily due to a $0.9 million increase
in asset optimization margins as a result of a more favorable
settlement of our asset management contracts in the current-year
period. This increase was coupled with a $0.4 million
increase in unrealized margins associated with asset
optimization activities.
Operating expenses for the three months ended June 30, 2008
were consistent with the prior-year quarter.
Nine
Months Ended June 30, 2008 compared with Nine Months Ended
June 30, 2007
Natural
Gas Distribution Segment
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the nine months ended June 30,
2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
830,652
|
|
|
$
|
799,457
|
|
|
$
|
31,195
|
|
Operating expenses
|
|
|
564,440
|
|
|
|
561,932
|
|
|
|
2,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
266,212
|
|
|
|
237,525
|
|
|
|
28,687
|
|
Miscellaneous income
|
|
|
7,654
|
|
|
|
6,633
|
|
|
|
1,021
|
|
Interest charges
|
|
|
88,802
|
|
|
|
91,164
|
|
|
|
(2,362
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
185,064
|
|
|
|
152,994
|
|
|
|
32,070
|
|
Income tax expense
|
|
|
71,622
|
|
|
|
60,530
|
|
|
|
11,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
113,442
|
|
|
$
|
92,464
|
|
|
$
|
20,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
261,692
|
|
|
|
265,508
|
|
|
|
(3,816
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
105,605
|
|
|
|
101,572
|
|
|
|
4,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
367,297
|
|
|
|
367,080
|
|
|
|
217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.44
|
|
|
$
|
0.46
|
|
|
$
|
(0.02
|
)
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
8.77
|
|
|
$
|
8.19
|
|
|
$
|
0.58
|
|
42
The following table shows our operating income by natural gas
distribution division for the nine months ended June 30,
2008 and 2007. The presentation of our natural gas distribution
operating income is included for financial reporting purposes
and may not be appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Colorado-Kansas
|
|
$
|
22,766
|
|
|
$
|
24,524
|
|
|
$
|
(1,758
|
)
|
Kentucky/Mid-States
|
|
|
49,800
|
|
|
|
44,913
|
|
|
|
4,887
|
|
Louisiana
|
|
|
36,254
|
|
|
|
39,540
|
|
|
|
(3,286
|
)
|
Mid-Tex
|
|
|
119,661
|
|
|
|
82,932
|
|
|
|
36,729
|
|
Mississippi
|
|
|
23,397
|
|
|
|
25,918
|
|
|
|
(2,521
|
)
|
West Texas
|
|
|
13,332
|
|
|
|
18,230
|
|
|
|
(4,898
|
)
|
Other
|
|
|
1,002
|
|
|
|
1,468
|
|
|
|
(466
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
266,212
|
|
|
$
|
237,525
|
|
|
$
|
28,687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $31.2 million increase in natural gas distribution
gross profit primarily reflects a $31.7 million net
increase in rates. The net increase in rates primarily was
attributable to the Mid-Tex Division which increased
$24.1 million as a result of the 2006 GRIP filing, the
previous and current year Mid-Tex rate cases and the absence of
a one time GRIP refund in the prior year. The current-year
period also reflects $10.7 million in rate increases in our
Kansas, Kentucky, Louisiana, Tennessee and West Texas service
areas.
Gross profit also increased approximately $6.5 million in
revenue-related taxes primarily due to higher revenues, on which
the tax is calculated, in the current-year period compared to
the prior-year period. This increase, partially offset by a
$2.5 million period-over-period increase in the associated
franchise and state gross receipts tax expense recorded as a
component of taxes other than income, resulted in a
$4.0 million increase in operating income, when compared
with the prior-year period.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income, increased by
$2.5 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $11.1 million, primarily due
to increased administrative and natural gas odorization costs
partially offset by lower employee costs. The increase in
operation and maintenance expense also reflects the absence in
the current-year period of a nonrecurring $4.3 million
deferral of hurricane-related operation and maintenance expenses
in the prior-year period.
The provision for doubtful accounts decreased $3.5 million
to $10.2 million for the nine months ended June 30,
2008. The decrease primarily was attributable to strong
collection efforts.
Depreciation and amortization expense decreased
$2.6 million for the nine months ended June 30, 2008
compared with the nine months ended June 30, 2007. The
decrease primarily was attributable to changes in depreciation
rates as a result of recent rate cases.
Operating expenses for the prior-year period also include a
$3.3 million noncash charge associated with the write-off
of software costs.
Results for the current-year period include a $1.2 million
gain on the sale of irrigation assets in our West Texas Division
during the fiscal 2008 second quarter.
Interest charges allocated to the natural gas distribution
segment decreased $2.4 million due to lower average
outstanding short-term debt balances in the current-year period
compared with the prior-year period.
43
Regulated
Transmission and Storage Segment
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the nine months ended
June 30, 2008 and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
69,409
|
|
|
$
|
62,149
|
|
|
$
|
7,260
|
|
Third-party transportation
|
|
|
58,946
|
|
|
|
45,162
|
|
|
|
13,784
|
|
Storage and park and lend services
|
|
|
6,288
|
|
|
|
6,943
|
|
|
|
(655
|
)
|
Other
|
|
|
8,129
|
|
|
|
8,393
|
|
|
|
(264
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
142,772
|
|
|
|
122,647
|
|
|
|
20,125
|
|
Operating expenses
|
|
|
68,565
|
|
|
|
57,578
|
|
|
|
10,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
74,207
|
|
|
|
65,069
|
|
|
|
9,138
|
|
Miscellaneous income
|
|
|
933
|
|
|
|
1,530
|
|
|
|
(597
|
)
|
Interest charges
|
|
|
20,453
|
|
|
|
20,852
|
|
|
|
(399
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
54,687
|
|
|
|
45,747
|
|
|
|
8,940
|
|
Income tax expense
|
|
|
19,351
|
|
|
|
16,661
|
|
|
|
2,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
35,336
|
|
|
$
|
29,086
|
|
|
$
|
6,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
593,452
|
|
|
|
528,144
|
|
|
|
65,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
429,758
|
|
|
|
359,447
|
|
|
|
70,311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $20.1 million increase in gross profit primarily was
attributable to a $10.0 million increase from rate
adjustments resulting from our 2006 and 2007 GRIP filings and a
$6.1 million increase from transportation volumes.
Consolidated throughput increased 20 percent primarily due
to increased transportation in the Barnett Shale region of
Texas. The improvement in gross profit also reflects increased
service fees and
per-unit
transportation margins due to favorable market conditions which
contributed $3.6 million. New compression contracts and
transportation capacity enhancements also contributed
$2.4 million. These increases were partially offset by a
$1.6 million decrease in sales of excess gas compared to
the same period in the prior year and a $1.0 million
decrease in parking and lending services due to market
conditions.
Operating expenses increased $11.0 million primarily due to
increased pipeline integrity and maintenance costs.
44
Natural
Gas Marketing Segment
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the nine months ended June 30, 2008
and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
55,599
|
|
|
$
|
44,320
|
|
|
$
|
11,279
|
|
Asset optimization
|
|
|
(10,339
|
)
|
|
|
38,558
|
|
|
|
(48,897
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,260
|
|
|
|
82,878
|
|
|
|
(37,618
|
)
|
Unrealized margins
|
|
|
14,404
|
|
|
|
2,733
|
|
|
|
11,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
59,664
|
|
|
|
85,611
|
|
|
|
(25,947
|
)
|
Operating expenses
|
|
|
22,775
|
|
|
|
21,126
|
|
|
|
1,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
36,889
|
|
|
|
64,485
|
|
|
|
(27,596
|
)
|
Miscellaneous income
|
|
|
1,775
|
|
|
|
5,816
|
|
|
|
(4,041
|
)
|
Interest charges
|
|
|
6,166
|
|
|
|
3,418
|
|
|
|
2,748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
32,498
|
|
|
|
66,883
|
|
|
|
(34,385
|
)
|
Income tax expense
|
|
|
12,933
|
|
|
|
26,515
|
|
|
|
(13,582
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,565
|
|
|
$
|
40,368
|
|
|
$
|
(20,803
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
348,789
|
|
|
|
306,931
|
|
|
|
41,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
298,351
|
|
|
|
264,325
|
|
|
|
34,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
17.5
|
|
|
|
21.5
|
|
|
|
(4.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $25.9 million decrease in our natural gas marketing
segments gross profit primarily reflects a
$48.9 million decrease in realized asset optimization
margins. As a result of a less volatile natural gas market
experienced during the year, AEM has been regularly deferring
storage withdrawals and resetting the associated financial
instruments to increase the potential gross profit it could
realize from its asset optimization activities in future
periods. As a result, AEM recognized settlement losses without
corresponding storage withdrawal gains during the current fiscal
year. Additionally, AEM experienced increased storage fees
charged by third parties during this time period. In the prior
year, AEM was able to recognize arbitrage gains as changes in
its originally scheduled storage injection and withdrawal plans
had a significantly smaller impact.
The decrease in realized asset optimization margins was
partially offset by an $11.3 million increase in realized
delivered gas margins. The increase reflects both increased
sales volumes and increased
per-unit
margins. Gross sales volumes increased 14 percent compared
with the prior-year period as we were able to successfully
execute our marketing initiatives. The increase in the
per-unit
margin primarily reflects favorable basis gains on certain
contracts. After excluding the effect of these location basis
gains, our
per-unit
margins decreased four percent in the current-year period due to
increased competition experienced during the third fiscal
quarter in a higher-priced natural gas market.
Gross profit margin was also favorably impacted by an
$11.7 million increase in unrealized margins attributable
to a narrowing of the spreads between current cash prices and
forward natural gas prices. The change in unrealized margins
also reflects the recognition of previously unrealized margins
as a component of realized margins as a result of injecting and
withdrawing gas and settling financial instruments as a part of
AEMs asset optimization activities.
45
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes, other than income taxes,
increased $1.6 million. The increase reflects
$2.4 million for the settlement of certain tax matters
partially offset by a $0.8 million decrease in employee and
other administrative costs.
Pipeline,
Storage and Other Segment
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the nine months ended June 30, 2008
and 2007 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Storage and transportation services
|
|
$
|
11,325
|
|
|
$
|
11,850
|
|
|
$
|
(525
|
)
|
Asset optimization
|
|
|
3,783
|
|
|
|
10,947
|
|
|
|
(7,164
|
)
|
Other
|
|
|
3,701
|
|
|
|
2,992
|
|
|
|
709
|
|
Unrealized margins
|
|
|
47
|
|
|
|
1,012
|
|
|
|
(965
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
18,856
|
|
|
|
26,801
|
|
|
|
(7,945
|
)
|
Operating expenses
|
|
|
6,061
|
|
|
|
6,235
|
|
|
|
(174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
12,795
|
|
|
|
20,566
|
|
|
|
(7,771
|
)
|
Miscellaneous income
|
|
|
6,243
|
|
|
|
5,588
|
|
|
|
655
|
|
Interest charges
|
|
|
1,755
|
|
|
|
5,465
|
|
|
|
(3,710
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
17,283
|
|
|
|
20,689
|
|
|
|
(3,406
|
)
|
Income tax expense
|
|
|
6,877
|
|
|
|
8,201
|
|
|
|
(1,324
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
10,406
|
|
|
$
|
12,488
|
|
|
$
|
(2,082
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline, storage and other gross profit decreased
$7.9 million primarily due to a $7.2 million decrease
in asset optimization margins as a result of a less volatile
natural gas market. The change in gross profit also reflects a
decrease of $1.0 million in unrealized margins associated
with asset optimization activities.
Operating expenses for the nine months ended June 30, 2008
remained generally unchanged compared with the prior-year period.
Liquidity
and Capital Resources
Our working capital and liquidity for capital expenditures and
other cash needs are provided from internally generated funds
and borrowings under our credit facilities and commercial paper
program. Additionally, from time to time, we raise funds from
the public debt and equity capital markets to fund our liquidity
needs.
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 activities
Period-over-period changes in our operating cash flows primarily
are attributable to changes in net income, working capital
changes, particularly within our natural gas distribution
segment resulting from the
46
price of natural gas and the timing of customer collections,
payments for natural gas purchases and deferred gas cost
recoveries.
For the nine months ended June 30, 2008, we generated
operating cash flow of $417.4 million from operating
activities compared with $552.7 million for the nine months
ended June 30, 2007. Period over period, our operating cash
flow was reduced primarily by cash required to collateralize our
risk management accounts, which reduced operating cash flows by
$84.2 million. Additionally, changes in accounts receivable
and gas stored underground reduced operating cash flow by
$219.9 million. These decreases were partially offset by
favorable timing of accounts payable and accrued liabilities
which increased operating cash flow by $141.8 million.
Finally, other changes in working capital and other items
increased operating cash flow by $27.0 million.
Cash
flows from investing activities
In recent years, a substantial portion of our cash resources has
been used to fund acquisitions and growth projects, our ongoing
construction program and improvements to information 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, our Mid-Tex, Louisiana, Mississippi and
West Texas natural gas distribution divisions and our Atmos
Pipeline Texas Division have rate designs that
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 2008 are expected to range from
$455 million to $465 million. For the nine months
ended June 30, 2008, we incurred $312.9 million for
capital expenditures compared with $263.0 million for the
nine months ended June 30, 2007. The increase in capital
spending primarily reflects an increase in main replacements in
our Mid-Tex Division and spending in the natural gas
distribution segment for our new automated metering initiative.
This initiative is expected to improve the efficiency of our
meter reading process through the installation of equipment that
automatically reads and transfers customer consumption and other
data to our customer information systems.
Cash
flows from financing activities
For the nine months ended June 30, 2008, our financing
activities reflected a use of cash of $114.4 million
compared with $5.2 million in the prior-year period. Our
significant financing activities for the nine months ended
June 30, 2008 and 2007 are summarized as follows.
|
|
|
|
|
During the nine months ended June 30, 2008, we repaid a net
$35.7 million under our short-term credit facilities. The
net repayment reflects the timing of the use of our line of
credit to finance natural gas purchases.
|
|
|
|
We repaid $9.9 million of long-term debt during the nine
months ended June 30, 2008 compared with $2.7 million
during the nine months ended June 30, 2007. The increased
payments during the current-year period reflects the prepayment
of $7.5 million of our Series P First Mortgage Bonds.
In connection with this prepayment we paid a $0.2 million
make-whole premium in accordance with the terms of the bonds and
related indenture.
|
|
|
|
In December 2006, we sold 6.3 million shares of common
stock in an offering, including the underwriters exercise
of their overallotment option of 0.8 million shares,
generating net proceeds of approximately $192 million. The
net proceeds from this issuance were used to reduce our
short-term debt.
|
|
|
|
During the nine months ended June 30, 2008, we paid
$87.8 million in cash dividends compared with
$83.1 million for the nine months ended June 30, 2007.
The increase in dividends paid over the prior-year period
reflects the increase in our dividend rate from $0.96 per share
during the nine months
|
47
|
|
|
|
|
ended June 30, 2007 to $0.975 per share during the nine
months ended June 30, 2008 combined with our December 2006
equity offering and new share issuances under our various equity
plans.
|
|
|
|
|
|
During the nine months ended June 30, 2008, we issued
0.7 million shares of common stock under our various equity
plans which generated net proceeds of $19.1 million. In
addition, we granted 0.5 million shares of common stock
under our 1998 Long-Term Incentive Plan.
|
The following table summarizes our share issuances for the nine
months ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
Direct Stock Purchase Plan
|
|
|
294,071
|
|
|
|
238,689
|
|
Retirement Savings Plan
|
|
|
410,350
|
|
|
|
306,920
|
|
1998 Long-Term Incentive Plan
|
|
|
538,100
|
|
|
|
500,684
|
|
Outside Directors Stock-for-Fee Plan
|
|
|
2,399
|
|
|
|
1,776
|
|
Public Offering
|
|
|
|
|
|
|
6,325,000
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
1,244,920
|
|
|
|
7,373,069
|
|
|
|
|
|
|
|
|
|
|
Credit
Facilities
As of June 30, 2008, we had a total of approximately
$1.5 billion of credit facilities, comprised of three
short-term committed credit facilities totaling
$918 million and, through AEM, an uncommitted credit
facility that can provide up to $580 million. Borrowings
under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas charged
by suppliers and the increased gas supplies required to meet
customers needs during periods of cold weather.
As of June 30, 2008, the amount available to us under our
credit facilities, net of outstanding letters of credit, was
$1.0 billion. We believe these credit facilities, combined
with our operating cash flows, will be sufficient to fund our
working capital needs. These facilities are described in further
detail in Note 4 to the unaudited condensed consolidated
financial statements.
Shelf
Registration
On December 4, 2006, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in new common stock
and/or debt
securities available for issuance. As of June 30, 2008, we
had approximately $450 million available for issuance under
the registration statement. Due to certain restrictions imposed
by one state regulatory commission on our ability to issue
securities under the registration statement, we are permitted to
issue a total of approximately $100 million of equity
securities, $50 million of senior debt securities and
$300 million of subordinated debt securities. In addition,
due to restrictions imposed by another state regulatory
commission, if the credit ratings on our senior unsecured debt
were to fall below investment grade from either
Standard & Poors Corporation (BBB-),
Moodys Investors Services, Inc. (Baa3) or Fitch Ratings,
Ltd. (BBB-), our ability to issue any type of debt securities
under the registration statement would be suspended until an
investment grade rating from all three credit rating agencies
was achieved.
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,
48
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). Our
current debt ratings are all considered investment grade and are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
|
Moodys
|
|
|
Fitch
|
|
|
Unsecured senior long-term debt
|
|
|
BBB
|
|
|
|
Baa3
|
|
|
|
BBB+
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-3
|
|
|
|
F-2
|
|
Currently, with respect to our unsecured senior long-term debt,
S&P maintains its positive outlook and Fitch maintains its
stable outlook. Moodys recently reaffirmed its stable
outlook. None of our ratings are currently under review.
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 independent 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
June 30, 2008. Our debt covenants are described in
Note 4 to the unaudited condensed consolidated financial
statements.
Capitalization
The following table presents our capitalization as of
June 30, 2008, September 30, 2007 and June 30,
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
113,257
|
|
|
|
2.6
|
%
|
|
$
|
150,599
|
|
|
|
3.5
|
%
|
|
$
|
|
|
|
|
|
%
|
Long-term debt
|
|
|
2,120,788
|
|
|
|
48.9
|
%
|
|
|
2,130,146
|
|
|
|
50.2
|
%
|
|
|
2,430,518
|
|
|
|
55.0
|
%
|
Shareholders equity
|
|
|
2,105,407
|
|
|
|
48.5
|
%
|
|
|
1,965,754
|
|
|
|
46.3
|
%
|
|
|
1,988,142
|
|
|
|
45.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
4,339,452
|
|
|
|
100.0
|
%
|
|
$
|
4,246,499
|
|
|
|
100.0
|
%
|
|
$
|
4,418,660
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt as a percentage of total capitalization, including
short-term debt, was 51.5 percent at June 30, 2008,
53.7 percent at September 30, 2007 and
55.0 percent at June 30, 2007. 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 through cash flow generated from operations,
continued issuance of new common stock under our Direct Stock
Purchase Plan and Retirement Savings Plan and access to the
equity capital markets.
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 nine months ended
June 30, 2008.
49
In February 2008, Atmos Pipeline and Storage, LLC announced
plans to construct and operate a salt-cavern gas storage project
in Franklin Parish, Louisiana. The project, located near several
large interstate pipelines, includes the development of three
5 billion cubic feet (Bcf) caverns for a total of
15 Bcf of working gas storage, with six-turn injection and
withdrawal capacity. Pending regulatory approval, the first
cavern is projected to go into operation by mid-2011, with the
other two caverns projected to be operational by 2012 and 2014.
Based on market demand, four additional storage caverns could
potentially be developed.
Risk
Management Activities
We conduct risk management activities through both our natural
gas distribution and natural gas marketing segments. In our
natural gas distribution segment, we use a combination of
physical storage, fixed physical contracts and fixed financial
contracts to reduce our exposure to unusually large
winter-period gas price increases. In our natural gas marketing
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 derivatives, 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 fair value hedges,
we could experience ineffectiveness or the hedges may no longer
meet the accounting requirements for hedge accounting, resulting
in the derivatives being treated as mark-to-market instruments
through earnings. In addition, natural gas inventory would be
reflected on the balance sheet at the lower of cost or market
instead of at fair value.
We record our derivatives as a component of risk management
assets and liabilities, which are classified as current or
noncurrent based upon the anticipated settlement date of the
underlying derivative. Substantially all of our derivative
financial instruments are valued using external market quotes
and indices. The following tables show the components of the
change in the fair value of our natural gas distribution and
natural gas marketing commodity derivative contracts for the
three and nine months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2007
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Distribution
|
|
|
Marketing
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
9,505
|
|
|
$
|
(22,975
|
)
|
|
$
|
3,802
|
|
|
$
|
(24,994
|
)
|
Contracts realized/settled
|
|
|
339
|
|
|
|
30,185
|
|
|
|
(144
|
)
|
|
|
15,994
|
|
Fair value of new contracts
|
|
|
5,675
|
|
|
|
|
|
|
|
(5,797
|
)
|
|
|
|
|
Other changes in value
|
|
|
21,847
|
|
|
|
(50,182
|
)
|
|
|
(5,385
|
)
|
|
|
24,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
$
|
37,366
|
|
|
$
|
(42,972
|
)
|
|
$
|
(7,524
|
)
|
|
$
|
15,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2007
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
Distribution
|
|
|
Marketing
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(21,053
|
)
|
|
$
|
26,808
|
|
|
$
|
(27,209
|
)
|
|
$
|
15,003
|
|
Contracts realized/settled
|
|
|
(26,971
|
)
|
|
|
(11,071
|
)
|
|
|
(27,662
|
)
|
|
|
(10,593
|
)
|
Fair value of new contracts
|
|
|
5,395
|
|
|
|
|
|
|
|
(7,058
|
)
|
|
|
|
|
Other changes in value
|
|
|
79,995
|
|
|
|
(58,709
|
)
|
|
|
54,405
|
|
|
|
11,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
$
|
37,366
|
|
|
$
|
(42,972
|
)
|
|
$
|
(7,524
|
)
|
|
$
|
15,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
The fair value of our natural gas distribution and natural gas
marketing derivative contracts at June 30, 2008, is
segregated below by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at June 30, 2008
|
|
|
|
Maturity in Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Greater
|
|
|
Total Fair
|
|
Source of Fair Value
|
|
Less than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
Than 5
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Prices actively quoted
|
|
$
|
(7,511
|
)
|
|
$
|
2,373
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(5,138
|
)
|
Prices based on models and other valuation methods
|
|
|
(275
|
)
|
|
|
(193
|
)
|
|
|
|
|
|
|
|
|
|
|
(468
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(7,786
|
)
|
|
$
|
2,180
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(5,606
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and Postretirement Benefits Obligations
For the nine months ended June 30, 2008 and 2007, our total
net periodic pension and other benefits cost was
$35.9 million and $36.4 million. These 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 total net periodic pension and other benefit costs remained
relatively unchanged during the current-year period when
compared with the prior-year period as the assumptions we made
during our annual pension plan valuation completed June 30,
2007 were consistent with the prior year. 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. At our June 30, 2007 measurement date, the
interest rates were consistent with rates at our prior-year
measurement date, which resulted in no change to our
6.30 percent discount rate used to determine our fiscal
2008 net periodic and post-retirement cost. In addition,
our expected return on our pension plan assets remained constant
at 8.25 percent.
We are currently in the process of completing our fiscal 2008
pension plan valuation. Based upon market conditions as of the
June 30, 2008 valuation date, we expect no significant
increase in our fiscal 2009 net periodic pension cost.
During the nine months ended June 30, 2008, we contributed
$6.7 million to our other postretirement plans, and we
expect to contribute a total of approximately $10 million
to these plans during fiscal 2008.
51
OPERATING
STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for
our natural gas distribution, regulated transmission and
storage, natural gas marketing and pipeline, storage and other
segments for the three and nine-month periods ended
June 30, 2008 and 2007.
Natural
Gas Distribution Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
METERS IN SERVICE, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,922,415
|
|
|
|
2,900,716
|
|
|
|
2,922,415
|
|
|
|
2,900,716
|
|
Commercial
|
|
|
271,542
|
|
|
|
274,273
|
|
|
|
271,542
|
|
|
|
274,273
|
|
Industrial
|
|
|
2,265
|
|
|
|
2,739
|
|
|
|
2,265
|
|
|
|
2,739
|
|
Public authority and other
|
|
|
9,234
|
|
|
|
16,576
|
|
|
|
9,234
|
|
|
|
16,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,205,456
|
|
|
|
3,194,304
|
|
|
|
3,205,456
|
|
|
|
3,194,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
41.7
|
|
|
|
43.9
|
|
|
|
41.7
|
|
|
|
43.9
|
|
HEATING DEGREE
DAYS(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
174
|
|
|
|
163
|
|
|
|
2,810
|
|
|
|
2,873
|
|
Percent of normal
|
|
|
102
|
%
|
|
|
98
|
%
|
|
|
100
|
%
|
|
|
101
|
%
|
SALES VOLUMES
MMcf(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
18,584
|
|
|
|
21,421
|
|
|
|
151,549
|
|
|
|
155,021
|
|
Commercial
|
|
|
15,199
|
|
|
|
16,672
|
|
|
|
82,325
|
|
|
|
83,231
|
|
Industrial
|
|
|
4,687
|
|
|
|
5,248
|
|
|
|
17,899
|
|
|
|
18,551
|
|
Public authority and other
|
|
|
2,887
|
|
|
|
1,911
|
|
|
|
9,919
|
|
|
|
8,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
41,357
|
|
|
|
45,252
|
|
|
|
261,692
|
|
|
|
265,508
|
|
Transportation volumes
|
|
|
33,211
|
|
|
|
30,431
|
|
|
|
109,002
|
|
|
|
105,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
74,568
|
|
|
|
75,683
|
|
|
|
370,694
|
|
|
|
370,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
352,893
|
|
|
$
|
294,756
|
|
|
$
|
1,878,855
|
|
|
$
|
1,795,124
|
|
Commercial
|
|
|
213,594
|
|
|
|
170,425
|
|
|
|
903,771
|
|
|
|
855,468
|
|
Industrial
|
|
|
53,843
|
|
|
|
44,345
|
|
|
|
167,154
|
|
|
|
162,621
|
|
Public authority and other
|
|
|
33,135
|
|
|
|
18,193
|
|
|
|
100,983
|
|
|
|
84,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
653,465
|
|
|
|
527,719
|
|
|
|
3,050,763
|
|
|
|
2,897,763
|
|
Transportation revenues
|
|
|
14,163
|
|
|
|
12,040
|
|
|
|
46,954
|
|
|
|
46,997
|
|
Other gas revenues
|
|
|
9,011
|
|
|
|
8,492
|
|
|
|
28,955
|
|
|
|
28,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
676,639
|
|
|
$
|
548,251
|
|
|
$
|
3,126,672
|
|
|
$
|
2,973,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average transportation revenue per Mcf
|
|
$
|
0.43
|
|
|
$
|
0.40
|
|
|
$
|
0.43
|
|
|
$
|
0.45
|
|
Average cost of gas per Mcf sold
|
|
$
|
11.53
|
|
|
$
|
7.90
|
|
|
$
|
8.77
|
|
|
$
|
8.19
|
|
See footnotes following these tables.
52
Regulated Transmission and Storage, Natural Gas Marketing and
Pipeline, Storage and Other Operations Sales and Statistical
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
CUSTOMERS, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
702
|
|
|
|
700
|
|
|
|
702
|
|
|
|
700
|
|
Municipal
|
|
|
56
|
|
|
|
64
|
|
|
|
56
|
|
|
|
64
|
|
Other
|
|
|
503
|
|
|
|
424
|
|
|
|
503
|
|
|
|
424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,261
|
|
|
|
1,188
|
|
|
|
1,261
|
|
|
|
1,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing
|
|
|
18.8
|
|
|
|
25.1
|
|
|
|
18.8
|
|
|
|
25.1
|
|
Pipeline, storage and other
|
|
|
1.2
|
|
|
|
1.9
|
|
|
|
1.2
|
|
|
|
1.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
20.0
|
|
|
|
27.0
|
|
|
|
20.0
|
|
|
|
27.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REGULATED TRANSMISSION AND STORAGE VOLUMES
MMcf(2)
|
|
|
181,112
|
|
|
|
157,825
|
|
|
|
593,452
|
|
|
|
528,144
|
|
NATURAL GAS MARKETING SALES VOLUMES
MMcf(2)
|
|
|
103,403
|
|
|
|
104,783
|
|
|
|
348,789
|
|
|
|
306,931
|
|
OPERATING REVENUES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated transmission and storage
|
|
$
|
46,286
|
|
|
$
|
36,707
|
|
|
$
|
142,772
|
|
|
$
|
122,647
|
|
Natural gas marketing
|
|
|
1,189,722
|
|
|
|
854,167
|
|
|
|
3,159,092
|
|
|
|
2,360,902
|
|
Pipeline, storage and other
|
|
|
3,880
|
|
|
|
2,073
|
|
|
|
20,629
|
|
|
|
27,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
1,239,888
|
|
|
$
|
892,947
|
|
|
$
|
3,322,493
|
|
|
$
|
2,511,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes to
preceding tables:
|
|
|
(1) |
|
A heating degree day is equivalent to each degree that the
average of the high and the low temperatures for a day is below
65 degrees. The colder the climate, the greater the number of
heating degree days. Heating degree days are used in the natural
gas industry to measure the relative coldness of weather and to
compare relative temperatures between one geographic area and
another. Generally, normal degree days are based on
30-year
average National Weather Service data for selected locations.
For service areas that have weather normalized operations,
normal degree days are used instead of actual degree days in
computing the total number of heating degree days. |
|
(2) |
|
Sales volumes and revenues reflect segment operations, including
intercompany sales and transportation amounts. |
RECENT
ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial
position, results of operations and cash flows are described in
Note 2 to the unaudited condensed consolidated financial
statements.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Information regarding our quantitative and qualitative
disclosures about market risk are disclosed in Item 7A in
our Annual Report on
Form 10-K
for the year ended September 30, 2007. During the nine
months ended June 30, 2008, there were no material changes
in our quantitative and qualitative disclosures about market
risk.
53
|
|
Item 4.
|
Controls
and Procedures
|
As indicated in the certifications in Exhibit 31 of this
report, the Companys Chief Executive Officer and Chief
Financial Officer have evaluated the Companys disclosure
controls and procedures as of June 30, 2008. Based on that
evaluation, these officers have concluded that the
Companys disclosure controls and procedures are effective
in ensuring that material information required to be disclosed
by the Company in the reports we file or submit under the
Securities Exchange Act of 1934 is accumulated and communicated
to our management, including our principal executive and
principal financial officers, as appropriate, to allow timely
decisions regarding required disclosure. In addition, there were
no changes during the Companys last fiscal quarter that
materially affected, or are reasonably likely to materially
affect, the Companys internal control over financial
reporting.
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
During the nine months ended June 30, 2008, 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 environmental-related matters that were disclosed
in Note 13 to our Annual Report on
Form 10-K
for the year ended September 30, 2007. 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.
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.
54
SIGNATURES
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)
John P. Reddy
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: August 6, 2008
55
EXHIBITS INDEX
Item 6(a)
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Exhibit
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Page
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Number
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Description
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Number
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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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* |
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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. |
56