e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
March 31, 2009
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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
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(IRS employer
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incorporation or
organization)
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identification no.)
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Three Lincoln Centre, Suite 1800
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75240
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5430 LBJ Freeway, Dallas, Texas
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(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 has submitted
electronically and posted on its Web site, if any, every
Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files).* Yes o No o
* The registrant has not yet been phased into the
interactive data requirements.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
Accelerated
Filer þ
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Accelerated
Filer o
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Non-Accelerated
Filer o
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Smaller
Reporting
Company o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act) Yes o No þ
Number of shares outstanding of each of the issuers
classes of common stock, as of April 22, 2009.
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Class
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Shares Outstanding
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No Par Value
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92,008,920
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TABLE OF CONTENTS
GLOSSARY
OF KEY TERMS
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AEC
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Atmos Energy Corporation
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AEH
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Atmos Energy Holdings, Inc.
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AEM
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Atmos Energy Marketing, LLC
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AOCI
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Accumulated other comprehensive income
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APS
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Atmos Pipeline and Storage, LLC
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Bcf
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Billion cubic feet
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FASB
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Financial Accounting Standards Board
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Fitch
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Fitch Ratings, Ltd.
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FSP
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FASB Staff Position
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GRIP
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Gas Reliability Infrastructure Program
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LPSC
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Louisiana Public Service Commission
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Mcf
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Thousand cubic feet
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MMcf
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Million cubic feet
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MPSC
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Mississippi Public Service Commission
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Moodys
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Moodys Investors Services, Inc.
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NYMEX
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New York Mercantile Exchange, Inc.
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PPA
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Pension Protection Act of 2006
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RRC
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Railroad Commission of Texas
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RRM
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Rate Review Mechanism
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S&P
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Standard & Poors Corporation
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SEC
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United States Securities and Exchange Commission
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SFAS
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Statement of Financial Accounting Standards
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WNA
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Weather Normalization Adjustment
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1
PART I.
FINANCIAL INFORMATION
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Item 1.
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Financial
Statements
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ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
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March 31,
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September 30,
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2009
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2008
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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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5,873,028
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$
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5,730,156
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Less accumulated depreciation and amortization
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1,609,836
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1,593,297
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Net property, plant and equipment
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4,263,192
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4,136,859
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Current assets
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Cash and cash equivalents
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482,085
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46,717
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Accounts receivable, net
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531,749
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477,151
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Gas stored underground
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327,288
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576,617
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Other current assets
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137,433
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184,619
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Total current assets
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1,478,555
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1,285,104
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Goodwill and intangible assets
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738,772
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739,086
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Deferred charges and other assets
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205,242
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|
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225,650
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$
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6,685,761
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$
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6,386,699
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CAPITALIZATION AND LIABILITIES
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Shareholders equity
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Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
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March 31, 2009 91,947,614 shares;
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September 30, 2008 90,814,683 shares
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$
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460
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$
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454
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Additional paid-in capital
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1,768,307
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1,744,384
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Retained earnings
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480,355
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343,601
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Accumulated other comprehensive loss
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(70,628
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)
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(35,947
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)
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Shareholders equity
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2,178,494
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2,052,492
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Long-term debt
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2,169,141
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2,119,792
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Total capitalization
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4,347,635
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4,172,284
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Current liabilities
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Accounts payable and accrued liabilities
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472,078
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395,388
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Other current liabilities
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413,764
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460,372
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Short-term debt
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350,542
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Current maturities of long-term debt
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400,225
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785
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Total current liabilities
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1,286,067
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1,207,087
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Deferred income taxes
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466,868
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441,302
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Regulatory cost of removal obligation
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313,486
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298,645
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Deferred credits and other liabilities
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271,705
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267,381
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$
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6,685,761
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$
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6,386,699
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|
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|
|
|
|
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|
See accompanying notes to condensed consolidated financial
statements
2
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
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Three Months Ended
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March 31
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2009
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2008
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(Unaudited)
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(In thousands, except
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per share data)
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Operating revenues
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|
|
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Natural gas distribution segment
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$
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1,230,420
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$
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1,521,856
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Regulated transmission and storage segment
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59,234
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51,440
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Natural gas marketing segment
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708,658
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1,128,653
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Pipeline, storage and other segment
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12,272
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|
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|
10,022
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Intersegment eliminations
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(189,178
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)
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(227,986
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)
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|
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1,821,406
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2,483,985
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Purchased gas cost
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|
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Natural gas distribution segment
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|
863,340
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1,164,332
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Regulated transmission and storage segment
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|
|
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|
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Natural gas marketing segment
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|
685,114
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|
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1,112,321
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Pipeline, storage and other segment
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|
1,656
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|
|
|
338
|
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Intersegment eliminations
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(188,755
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)
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(227,400
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)
|
|
|
|
|
|
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|
|
|
|
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1,361,355
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|
|
|
2,049,591
|
|
|
|
|
|
|
|
|
|
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Gross profit
|
|
|
460,051
|
|
|
|
434,394
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
121,740
|
|
|
|
120,053
|
|
Depreciation and amortization
|
|
|
53,450
|
|
|
|
48,790
|
|
Taxes, other than income
|
|
|
58,314
|
|
|
|
54,408
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
233,504
|
|
|
|
223,251
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
226,547
|
|
|
|
211,143
|
|
Miscellaneous income (expense)
|
|
|
(1,565
|
)
|
|
|
1,467
|
|
Interest charges
|
|
|
35,533
|
|
|
|
33,516
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
189,449
|
|
|
|
179,094
|
|
Income tax expense
|
|
|
60,446
|
|
|
|
67,560
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
1.42
|
|
|
$
|
1.25
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
1.41
|
|
|
$
|
1.24
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.330
|
|
|
$
|
0.325
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
90,895
|
|
|
|
89,314
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
91,567
|
|
|
|
89,990
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
2,286,388
|
|
|
$
|
2,450,033
|
|
Regulated transmission and storage segment
|
|
|
113,916
|
|
|
|
96,486
|
|
Natural gas marketing segment
|
|
|
1,496,153
|
|
|
|
1,969,370
|
|
Pipeline, storage and other segment
|
|
|
28,720
|
|
|
|
16,749
|
|
Intersegment eliminations
|
|
|
(387,439
|
)
|
|
|
(391,143
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
3,537,738
|
|
|
|
4,141,495
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
1,620,924
|
|
|
|
1,819,309
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
1,442,586
|
|
|
|
1,907,075
|
|
Pipeline, storage and other segment
|
|
|
5,559
|
|
|
|
1,067
|
|
Intersegment eliminations
|
|
|
(386,594
|
)
|
|
|
(389,988
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,682,475
|
|
|
|
3,337,463
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
855,263
|
|
|
|
804,032
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
256,495
|
|
|
|
241,242
|
|
Depreciation and amortization
|
|
|
106,576
|
|
|
|
97,303
|
|
Taxes, other than income
|
|
|
102,451
|
|
|
|
95,835
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
465,522
|
|
|
|
434,380
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
389,741
|
|
|
|
369,652
|
|
Miscellaneous income (expense)
|
|
|
(1,866
|
)
|
|
|
1,374
|
|
Interest charges
|
|
|
74,524
|
|
|
|
70,333
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
313,351
|
|
|
|
300,693
|
|
Income tax expense
|
|
|
108,385
|
|
|
|
115,356
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
2.26
|
|
|
$
|
2.08
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
2.24
|
|
|
$
|
2.06
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.66
|
|
|
$
|
0.65
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
90,637
|
|
|
|
89,133
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
91,311
|
|
|
|
89,817
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
Charged to depreciation and amortization
|
|
|
106,576
|
|
|
|
97,303
|
|
Charged to other accounts
|
|
|
21
|
|
|
|
67
|
|
Deferred income taxes
|
|
|
97,892
|
|
|
|
72,277
|
|
Other
|
|
|
13,634
|
|
|
|
6,853
|
|
Net assets/liabilities from risk management activities
|
|
|
5,810
|
|
|
|
(22,667
|
)
|
Net change in operating assets and liabilities
|
|
|
185,723
|
|
|
|
140,022
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
614,622
|
|
|
|
479,192
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(221,330
|
)
|
|
|
(198,722
|
)
|
Other, net
|
|
|
(3,925
|
)
|
|
|
(3,132
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(225,255
|
)
|
|
|
(201,854
|
)
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Net decrease in short-term debt
|
|
|
(353,468
|
)
|
|
|
(150,582
|
)
|
Net proceeds from debt offering
|
|
|
446,188
|
|
|
|
|
|
Settlement of Treasury lock agreement
|
|
|
1,938
|
|
|
|
|
|
Repayment of long-term debt
|
|
|
(625
|
)
|
|
|
(2,253
|
)
|
Cash dividends paid
|
|
|
(60,446
|
)
|
|
|
(58,431
|
)
|
Issuance of common stock
|
|
|
12,414
|
|
|
|
12,839
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
46,001
|
|
|
|
(198,427
|
)
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
435,368
|
|
|
|
78,911
|
|
Cash and cash equivalents at beginning of period
|
|
|
46,717
|
|
|
|
60,725
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
482,085
|
|
|
$
|
139,636
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
5
ATMOS
ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
(Unaudited)
March 31, 2009
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 conducted through 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 Southeast and Midwest
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 financial
instruments.
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS
owns and operates a 21 mile pipeline located in New
Orleans, Louisiana. This pipeline is used primarily to aggregate
gas supply for our regulated natural gas distribution division
in Louisiana and for AEM, but also provides limited third party
transportation services.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are asset management plans with regulated
affiliates of the Company which have been approved by applicable
state regulatory commissions. Generally, these asset management
plans require APS to share with our regulated customers a
portion of the profits earned from these arrangements.
Further, APS owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
pipeline capacity to meet customer demand during peak periods.
Finally, APS manages our natural gas gathering operations, which
were limited in nature as of March 31, 2009.
|
|
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 our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. Because of
seasonal and other factors, the results of operations for the
six-month period ended March 31, 2009 are not indicative of
our results of operations for the full 2009 fiscal year, which
ends September 30, 2009.
Significant
accounting policies
Our accounting policies are described in Note 2 to the
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008, and there
were no changes to those policies. However, during the six
months ended March 31, 2009, we recognized a non-recurring
$8.3 million increase in gross profit associated with a
one-time update to our estimate for gas delivered to customers
but not yet billed, resulting from base rate changes in several
jurisdictions.
During the second quarter of fiscal 2009, we updated the tax
rates used to record deferred taxes. The one-time tax benefit
resulted in a favorable impact to net income of
$11.3 million.
Additionally, during the second quarter of fiscal 2009, we
completed our annual goodwill impairment assessment. Based on
the assessment performed, we determined that our goodwill was
not impaired.
Effective October 1, 2008, the Company adopted Statement of
Financial Accounting Standards (SFAS) 157, Fair Value
Measurements, the measurement date requirements of
SFAS 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans, an amendment of FASB
Statements No. 87, 88, 106, and 132(R), SFAS 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of FASB Statement
No. 115, SFAS 161, Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB
Statement No. 133 and FASB Staff Position (FSP)
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments. Except for the adoption of these accounting
pronouncements, which are further discussed below, there were no
significant changes to our accounting policies during the six
months ended March 31, 2009.
SFAS 157 defines fair value, establishes a framework for
measuring fair value and enhances disclosure on fair value
measurements required under other accounting pronouncements but
does not change existing
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
guidance as to whether or not an instrument is carried at fair
value. The adoption of this standard did not materially impact
our financial position, results of operations or cash flows. The
new disclosures required by this standard are presented in
Note 4.
Effective October 1, 2008, the Company adopted the
measurement date requirements of SFAS 158 using the
remeasurement approach. Under this approach, the Company
remeasured its projected benefit obligation, fair value of plan
assets and its fiscal 2009 net periodic cost. In accordance
with the transition rules of SFAS 158, the impact of
changing the measurement date from June 30, 2008 to
September 30, 2008 decreased retained earnings by
$7.8 million, net of tax, decreased the unrecognized
actuarial loss by $9.0 million and increased our
postretirement liabilities by $3.5 million during the first
quarter of fiscal 2009.
SFAS 159 permits an entity to measure certain financial
assets and financial liabilities at fair value. The objective of
the standard is to improve financial reporting by allowing
entities to mitigate volatility in reported earnings caused by
measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. Entities
that elect the fair value option will report unrealized gains
and losses in earnings at each subsequent reporting date. The
fair value option may be elected on an
instrument-by-instrument
basis. The fair value option is irrevocable, unless a new
election date occurs. The adoption of this standard did not
impact our financial position, results of operations or cash
flows.
SFAS 161 expands the disclosure requirements for derivative
instruments and hedging activities. This statement requires
specific disclosures regarding how and why an entity uses
derivative instruments; the accounting for derivative
instruments and related hedged items; and how derivative
instruments and related hedged items affect an entitys
financial position, results of operations and cash flows. Since
SFAS 161 only requires additional disclosures concerning
derivatives and hedging activities, this standard did not have
an impact on our financial position, results of operations or
cash flows. The new disclosures required by this standard are
presented in Note 3.
In April 2009, the FASB issued FSP
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments. This FSP requires companies to disclose the
fair value of financial instruments for which it is practicable
to estimate the value and the methods and significant
assumptions used to estimate the fair value. The disclosure is
required for interim and annual reports. The disclosure
requirements of this FSP are presented in Note 4.
Regulatory
assets and liabilities
We record certain costs as regulatory assets in accordance with
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
March 31, 2009 and September 30, 2008 included the
following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
89,244
|
|
|
$
|
100,563
|
|
Merger and integration costs, net
|
|
|
7,374
|
|
|
|
7,586
|
|
Deferred gas costs
|
|
|
58,660
|
|
|
|
55,103
|
|
Environmental costs
|
|
|
741
|
|
|
|
980
|
|
Rate case costs
|
|
|
9,144
|
|
|
|
12,885
|
|
Deferred franchise fees
|
|
|
597
|
|
|
|
651
|
|
Deferred income taxes, net
|
|
|
343
|
|
|
|
343
|
|
Other
|
|
|
7,846
|
|
|
|
8,120
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
173,949
|
|
|
$
|
186,231
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
61,177
|
|
|
$
|
76,979
|
|
Regulatory cost of removal obligation
|
|
|
329,120
|
|
|
|
317,273
|
|
Other
|
|
|
5,499
|
|
|
|
5,639
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
395,796
|
|
|
$
|
399,891
|
|
|
|
|
|
|
|
|
|
|
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
six-month periods ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31
|
|
|
Six Months Ended March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
Unrealized holding losses on investments, net of tax benefit of
$429 and $1,385 for the three months ended March 31, 2009
and 2008 and of $3,759 and $671 for the six months ended
March 31, 2009 and 2008
|
|
|
(862
|
)
|
|
|
(2,262
|
)
|
|
|
(6,295
|
)
|
|
|
(1,097
|
)
|
Other than temporary impairment of investments, net of tax
expense of $790 for the six months ended March 31, 2009
|
|
|
|
|
|
|
|
|
|
|
1,288
|
|
|
|
|
|
Amortization and unrealized gain on interest rate hedging
transactions, net of tax expense of $1,353 and $482 for the
three months ended March 31, 2009 and 2008 and $1,835 and
$964 for the six months ended March 31, 2009 and 2008
|
|
|
1,854
|
|
|
|
787
|
|
|
|
2,641
|
|
|
|
1,574
|
|
Net unrealized gains (losses) on commodity hedging transactions,
net of tax expense (benefit) of $(7,524) and $2,260 for the
three months ended March 31, 2009 and 2008 and $(21,341)
and $7,197 for the six months ended March 31, 2009 and 2008
|
|
|
(9,771
|
)
|
|
|
3,690
|
|
|
|
(32,315
|
)
|
|
|
11,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
120,224
|
|
|
$
|
113,749
|
|
|
$
|
170,285
|
|
|
$
|
197,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss, net of tax, as of
March 31, 2009 and September 30, 2008 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) on investments
|
|
$
|
(4,097
|
)
|
|
$
|
910
|
|
Treasury lock agreements
|
|
|
(8,463
|
)
|
|
|
(11,104
|
)
|
Cash flow hedges
|
|
|
(58,068
|
)
|
|
|
(25,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(70,628
|
)
|
|
$
|
(35,947
|
)
|
|
|
|
|
|
|
|
|
|
We currently use financial instruments to mitigate commodity
price risk. Additionally, we periodically utilize financial
instruments to manage interest rate risk. The objectives and
strategies for using financial instruments have been tailored to
our regulated and nonregulated businesses. The accounting for
these financial instruments is fully described in Note 2 to
the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. Currently, we
utilize financial instruments in our natural gas distribution,
natural gas marketing and pipeline, storage and other segments.
However, our pipeline, storage
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and other segment uses financial instruments acquired from AEM
on the same terms that AEM received from an independent
counterparty. On a consolidated basis, these financial
instruments are reported in the natural gas marketing segment.
We currently do not manage commodity price risk with financial
instruments in our regulated transmission and storage segment.
Our financial instruments do not contain any credit-risk-related
or other contingent features that could cause accelerated
payments when our financial instruments are in net liability
positions.
Regulated
Commodity Risk Management Activities
In our natural gas distribution segment, our customers are
exposed to the effect of volatile natural gas prices. We manage
this exposure through a combination of physical storage,
fixed-price forward contracts and financial instruments,
primarily over-the-counter swap and option contracts, in an
effort to minimize the impact of natural gas price volatility on
our customers during the winter heating season.
Our natural gas distribution gas supply department is
responsible for executing this segments commodity risk
management activities in conformity with regulatory
requirements. In jurisdictions where we are permitted to
mitigate commodity price risk through financial instruments, the
relevant regulatory authorities may establish the level of
heating season gas purchases that can be hedged. If the
regulatory authority does not establish this level, we seek to
hedge between 25 and 50 percent of anticipated heating
season gas purchases using financial instruments. For the
2008-2009
heating season, in the jurisdictions where we are permitted to
utilize financial instruments, we anticipated hedging
approximately 29 percent, or 25.5 Bcf of the winter
flowing gas requirements. We have not designated these financial
instruments as hedges pursuant to SFAS 133, Accounting
for Derivative Instruments and Hedging Activities.
The costs associated with and the gains and losses arising from
the use of financial instruments to mitigate commodity price
risk are included in our purchased gas adjustment mechanisms in
accordance with regulatory requirements. Therefore, changes in
the fair value of these financial instruments are initially
recorded as a component of deferred gas costs and recognized in
the consolidated statement of income as a component of purchased
gas cost when the related costs are recovered through our rates
and recognized in revenue in accordance with SFAS 71.
Accordingly, there is no earnings impact to our natural gas
distribution segment as a result of the use of financial
instruments.
Nonregulated
Commodity Risk Management Activities
Our natural gas marketing segment, through AEM, aggregates and
purchases gas supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request.
We also perform asset optimization activities in both our
natural gas marketing segment and pipeline, storage and other
segment. Through asset optimization activities, we seek to
maximize the economic value associated with the storage and
transportation capacity we own or control. We attempt to meet
this objective by engaging in natural gas storage transactions
in which we seek to find and profit from 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. Over time, gains and losses on the sale of
storage gas
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
inventory will be offset by gains and losses on the financial
instruments, resulting in the realization of the economic gross
profit margin we anticipated at the time we structured the
original transaction.
As a result of these activities, our nonregulated operations are
exposed to risks associated with changes in the market price of
natural gas. We manage our exposure to such risks through a
combination of physical storage and financial instruments,
including futures, over-the-counter and exchange-traded options
and swap contracts with counterparties. Futures contracts
provide the right to buy or sell the commodity at a fixed price
in the future. Option contracts provide the right, but not the
requirement, to buy or sell the commodity at a fixed price. Swap
contracts require receipt of payment for the commodity based on
the difference between a fixed price and the market price on the
settlement date.
We use financial instruments, designated as cash flow hedges of
anticipated purchases and sales at index prices, to mitigate the
commodity price risk in our natural gas marketing segment
associated with deliveries under fixed-priced forward contracts
to deliver gas to customers. These financial instruments have
maturity dates ranging from one to 46 months. The effective
portion of the unrealized gains and losses arising from the use
of cash flow hedges is recorded as a component of accumulated
other comprehensive income (AOCI) on the balance sheet. Amounts
associated with cash flow hedges recognized in the income
statement include (i) the amount of unrealized gain or loss
that has been reclassified from AOCI when the hedged volumes are
sold and (ii) the amount of ineffectiveness associated with
these hedges in the period the ineffectiveness arises.
We use financial instruments, designated as fair value hedges,
to hedge the exposure to changes in the fair value of our
natural gas inventory used in our asset optimization activities
in our natural gas marketing and pipeline, storage and other
segments. Therefore, gains and losses arising from these
financial instruments should offset the changes in the fair
value of the hedged item to the extent the hedging relationship
is effective. Ineffectiveness is recognized in the income
statement in the period the ineffectiveness arises.
Also, in our natural gas marketing segment, we use storage swaps
and futures to capture additional storage arbitrage
opportunities that arise subsequent to the execution of the
original fair value hedge associated with our physical natural
gas inventory, basis swaps to insulate and protect the economic
value of our fixed price and storage books and various
over-the-counter and exchange-traded options. These financial
instruments have not been designated as hedges pursuant to
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities.
Our nonregulated risk management activities are controlled
through various risk management policies and procedures. Our
Audit Committee has oversight responsibility for our
nonregulated risk management limits and policies. Our risk
management committee, comprised of corporate and business unit
officers, is responsible for establishing and enforcing our
nonregulated risk management policies and procedures.
Under our risk management policies, we seek to match our
financial instrument positions to our physical storage positions
as well as our expected current and future sales and purchase
obligations to maintain no open positions at the end of each
trading day. The determination of our net open position as of
any day, however, requires us to make assumptions as to future
circumstances, including the use of gas by our customers in
relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. We can also be affected by intraday
fluctuations of gas prices, since the price of natural gas
purchased or sold for future delivery earlier in the day may not
be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on March 31, 2009, AEH
had net open positions (including existing storage) of less than
0.1 Bcf.
12
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Interest
Rate Risk Management Activities
In March 2009, we entered into a Treasury lock agreement to fix
the Treasury yield component of the interest cost associated
with our $450 million 8.50% senior notes (the Senior
Notes Offering), which was completed on March 26, 2009. The
Senior Notes Offering is discussed in Note 5. We designated
this Treasury lock as a cash flow hedge of an anticipated
transaction. This Treasury lock was settled on March 23,
2009 with the receipt of $1.9 million from the counterparty
due to an increase in the 10 year Treasury rates between
inception of the Treasury lock and settlement. Because the
Treasury lock was effective, the net $1.2 million
unrealized gain was recorded as a component of accumulated other
comprehensive income and will be recognized over the
10 year life of the senior notes.
In prior years, we similarly managed interest rate risk by
entering into Treasury lock agreements to fix the Treasury yield
component of the interest cost associated with anticipated
financings. These Treasury locks were settled at various times
at a net loss. These realized gains and losses were recorded as
a component of accumulated other comprehensive income (loss) and
are being recognized as a component of interest expense over the
life of the associated notes from the date of settlement. The
remaining amortization periods for these Treasury locks extend
through fiscal 2035. However, the majority of the remaining
amounts of these Treasury locks will be recognized as a
component of interest expense through fiscal 2019.
Quantitative
Disclosures Related to Financial Instruments
The following tables present detailed information concerning the
impact of financial instruments on our condensed consolidated
balance sheet and income statements.
As of March 31, 2009, our financial instruments were
comprised of both long and short commodity positions. A long
position is a contract to purchase the commodity, while a short
position is a contract to sell the commodity. As of
March 31, 2009, we had net long/(short) commodity contracts
outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
Hedge
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
Contract Type
|
|
Designation
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
|
|
|
Quantity (MMcf)
|
|
|
Commodity contracts
|
|
Fair Value
|
|
|
|
|
|
|
(19,052
|
)
|
|
|
(1,410
|
)
|
|
|
Cash Flow
|
|
|
|
|
|
|
38,822
|
|
|
|
(1,905
|
)
|
|
|
Not designated
|
|
|
7,727
|
|
|
|
109,450
|
|
|
|
(688
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,727
|
|
|
|
129,220
|
|
|
|
(4,003
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Instruments on the Balance Sheet
The following tables present the fair value and balance sheet
classification of our financial instruments by operating segment
as of March 31, 2009 and September 30, 2008. As
required by SFAS 161, the fair value amounts below are
presented on a gross basis and do not reflect the netting of
asset and liability positions permitted under the terms of our
master netting arrangements. Further, the amounts below do not
include $79.1 million and $56.6 million of cash held
on deposit in margin accounts as of March 31, 2009 and
September 30, 2008 to collateralize certain financial
instruments. Therefore, these gross balances are not indicative
of either our actual credit exposure or net economic exposure.
Additionally, the amounts below will
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
not be equal to the amounts presented on our condensed
consolidated balance sheet, nor will they be equal to the fair
value information presented for our financial instruments in
Note 4.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
73,163
|
|
|
$
|
73,163
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
8,018
|
|
|
|
8,018
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(116,698
|
)
|
|
|
(116,698
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(1,712
|
)
|
|
|
(1,712
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
(37,229
|
)
|
|
|
(37,229
|
)
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
676
|
|
|
|
40,262
|
|
|
|
40,938
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
5,108
|
|
|
|
5,108
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(22,535
|
)
|
|
|
(39,098
|
)
|
|
|
(61,633
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(4
|
)
|
|
|
(1,689
|
)
|
|
|
(1,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(21,863
|
)
|
|
|
4,583
|
|
|
|
(17,280
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(21,863
|
)
|
|
$
|
(32,646
|
)
|
|
$
|
(54,509
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
101,191
|
|
|
$
|
101,191
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
4,984
|
|
|
|
4,984
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(89,397
|
)
|
|
|
(89,397
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(206
|
)
|
|
|
(206
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
16,572
|
|
|
|
16,572
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
|
|
|
|
20,010
|
|
|
|
20,010
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
1,093
|
|
|
|
1,093
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(58,566
|
)
|
|
|
(20,145
|
)
|
|
|
(78,711
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(5,111
|
)
|
|
|
(988
|
)
|
|
|
(6,099
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(63,677
|
)
|
|
|
(30
|
)
|
|
|
(63,707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(63,677
|
)
|
|
$
|
16,542
|
|
|
$
|
(47,135
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Impact of
Financial Instruments on the Income Statement
The following tables present the impact that financial
instruments had on our condensed consolidated income statement,
by operating segment, as applicable, for the three and six
months ended March 31, 2009 and 2008.
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. For the three months ended March 31,
2009 and 2008 we recognized a gain arising from fair value and
cash flow hedge ineffectiveness of $4.2 million and
$6.5 million. For the six months ended March 31, 2009
and 2008 we recognized a gain arising from fair value and cash
flow hedge ineffectiveness of $24.6 million and
$45.2 million. Additional information regarding
ineffectiveness recognized in the income statement is included
in the tables below. Although these unrealized gains and losses
are currently recorded in our income statement, they are not
necessarily indicative of the economic gross profit we
anticipate realizing when the underlying physical and financial
transactions are settled.
Fair
Value Hedges
The impact of commodity contracts designated as fair value
hedges and the related hedged item on our condensed consolidated
income statement for the three and six months ended
March 31, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
19,870
|
|
|
$
|
2,105
|
|
|
$
|
21,975
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(18,562
|
)
|
|
|
(437
|
)
|
|
|
(18,999
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
1,308
|
|
|
$
|
1,668
|
|
|
$
|
2,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
2,327
|
|
|
$
|
|
|
|
$
|
2,327
|
|
Timing ineffectiveness
|
|
|
(1,019
|
)
|
|
|
1,668
|
|
|
|
649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,308
|
|
|
$
|
1,668
|
|
|
$
|
2,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
(33,448
|
)
|
|
$
|
(735
|
)
|
|
$
|
(34,183
|
)
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
39,922
|
|
|
|
1,352
|
|
|
|
41,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
6,474
|
|
|
$
|
617
|
|
|
$
|
7,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(739
|
)
|
|
$
|
|
|
|
$
|
(739
|
)
|
Timing ineffectiveness
|
|
|
7,213
|
|
|
|
617
|
|
|
|
7,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,474
|
|
|
$
|
617
|
|
|
$
|
7,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
45,553
|
|
|
$
|
6,044
|
|
|
$
|
51,597
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(30,422
|
)
|
|
|
(1,990
|
)
|
|
|
(32,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
15,131
|
|
|
$
|
4,054
|
|
|
$
|
19,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
4,279
|
|
|
$
|
|
|
|
$
|
4,279
|
|
Timing ineffectiveness
|
|
|
10,852
|
|
|
|
4,054
|
|
|
|
14,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,131
|
|
|
$
|
4,054
|
|
|
$
|
19,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
(16,221
|
)
|
|
$
|
1,387
|
|
|
$
|
(14,834
|
)
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
57,523
|
|
|
|
2,410
|
|
|
|
59,933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
41,302
|
|
|
$
|
3,797
|
|
|
$
|
45,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
1,217
|
|
|
$
|
|
|
|
$
|
1,217
|
|
Timing ineffectiveness
|
|
|
40,085
|
|
|
|
3,797
|
|
|
|
43,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
41,302
|
|
|
$
|
3,797
|
|
|
$
|
45,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness arises from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the hedge instruments. Timing
ineffectiveness arises due to changes in the difference between
the spot price and the futures price, as well as the difference
between the timing of the settlement of the futures and the
valuation of the underlying physical commodity. As the commodity
contract nears the settlement date, spot to forward price
differences should converge, which should reduce or eliminate
the impact of this ineffectiveness on revenue.
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
Flow Hedges
The impact of cash flow hedges on our condensed consolidated
income statements for the three and six months ended
March 31, 2009 and 2008 is presented below. Note that this
presentation does not reflect the financial impact arising from
the hedged physical transaction. Therefore, this presentation is
not indicative of the economic gross profit we realized when the
underlying physical and financial transactions were settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(48,585
|
)
|
|
$
|
16,170
|
|
|
$
|
(32,415
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
1,180
|
|
|
|
|
|
|
|
1,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(47,405
|
)
|
|
|
16,170
|
|
|
|
(31,235
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(1,269
|
)
|
|
$
|
(47,405
|
)
|
|
$
|
16,170
|
|
|
$
|
(32,504
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(8,040
|
)
|
|
$
|
13,492
|
|
|
$
|
5,452
|
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(634
|
)
|
|
|
|
|
|
|
(634
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(8,674
|
)
|
|
|
13,492
|
|
|
|
4,818
|
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(1,269
|
)
|
|
$
|
(8,674
|
)
|
|
$
|
13,492
|
|
|
$
|
3,549
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(76,829
|
)
|
|
$
|
24,139
|
|
|
$
|
(52,690
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
5,372
|
|
|
|
|
|
|
|
5,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(71,457
|
)
|
|
|
24,139
|
|
|
|
(47,318
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(2,538
|
)
|
|
$
|
(71,457
|
)
|
|
$
|
24,139
|
|
|
$
|
(49,856
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(17,294
|
)
|
|
$
|
13,916
|
|
|
$
|
(3,378
|
)
|
Gain arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
126
|
|
|
|
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(17,168
|
)
|
|
|
13,916
|
|
|
|
(3,252
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(2,538
|
)
|
|
$
|
(17,168
|
)
|
|
$
|
13,916
|
|
|
$
|
(5,790
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the gains and losses arising from
hedging transactions that were recognized as a component of
other comprehensive income (loss), net of taxes, for the three
and six months ended March 31, 2009 and 2008. The amounts
included in the table below exclude gains and losses arising
from ineffectiveness because these amounts are immediately
recognized in the income statement as incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
1,221
|
|
|
$
|
|
|
|
$
|
1,221
|
|
|
$
|
|
|
Forward commodity contracts
|
|
|
(29,544
|
)
|
|
|
7,070
|
|
|
|
(64,659
|
)
|
|
|
9,649
|
|
Recognition of (gains) losses in earnings due to
settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
633
|
|
|
|
787
|
|
|
|
1,420
|
|
|
|
1,574
|
|
Forward commodity contracts
|
|
|
19,773
|
|
|
|
(3,380
|
)
|
|
|
32,344
|
|
|
|
2,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) from hedging, net of
tax(1)
|
|
$
|
(7,917
|
)
|
|
$
|
4,477
|
|
|
$
|
(29,674
|
)
|
|
$
|
13,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
The following amounts, net of deferred taxes, represent the
expected recognition in earnings of the deferred losses recorded
in AOCI associated with our financial instruments, based upon
the fair values of these financial instruments as of
March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Commodity
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Next twelve months
|
|
$
|
(2,426
|
)
|
|
$
|
(54,233
|
)
|
|
$
|
(56,659
|
)
|
Thereafter
|
|
|
(6,037
|
)
|
|
|
(3,835
|
)
|
|
|
(9,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
$
|
(8,463
|
)
|
|
$
|
(58,068
|
)
|
|
$
|
(66,531
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Financial
Instruments Not Designated as Hedges
The impact of financial instruments that have not been
designated as hedges on our condensed consolidated income
statements for the three and six months ended March 31,
2009 and 2008 is presented below. Note that this presentation
does not reflect the expected gains or losses arising from the
underlying physical transactions associated with these financial
instruments. Therefore, this presentation is not indicative of
the economic gross profit we realized when the underlying
physical and financial transactions were settled.
As discussed above, financial instruments used in our natural
gas distribution segment are not designated as hedges. However,
there is no earnings impact to our natural gas distribution
segment as a result of the use of these financial instruments
because the gains and losses arising from the use of these
financial instruments are recognized in the consolidated
statement of income as a component of purchased gas cost when
the related costs are recovered through our rates and recognized
in revenue. Accordingly, the impact of these financial
instruments is excluded from this presentation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31
|
|
|
Six Months Ended March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Natural gas marketing commodity contracts
|
|
$
|
10,593
|
|
|
$
|
(14,120
|
)
|
|
$
|
6,761
|
|
|
$
|
(13,794
|
)
|
Pipeline, storage and other commodity contracts
|
|
|
183
|
|
|
|
(245
|
)
|
|
|
100
|
|
|
|
(889
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
10,776
|
|
|
$
|
(14,365
|
)
|
|
$
|
6,861
|
|
|
$
|
(14,683
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Fair
Value Measurements
|
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS 157, Fair Value Measurements,
which defines fair value, establishes a framework for measuring
fair value in generally accepted accounting principles (GAAP)
and expands disclosures about fair value measurements. This
Statement does not require any new fair value measurements;
rather it provides guidance on how to perform fair value
measurements as required or permitted under previous accounting
pronouncements.
We prospectively adopted the provisions of SFAS 157 on
October 1, 2008 for most of the financial assets and
liabilities recorded on our balance sheet at fair value.
Adoption of this statement for these assets and liabilities did
not have a material impact on our financial position, results of
operations or cash flows.
In February 2008, the FASB issued FSP
FAS 157-2,
Effective Date of FASB Statement No. 157, which
provided a one-year deferral of SFAS 157 for nonrecurring
fair value measurements associated with our nonfinancial assets
and liabilities. Under this partial deferral, SFAS 157 will
not be effective until October 1, 2009 for fair value
measurements for the following:
|
|
|
|
|
Asset retirement obligations
|
|
|
|
Most nonfinancial assets and liabilities that may be acquired in
a business combination
|
|
|
|
Impairment analyses performed for nonfinancial assets
|
We believe the adoption of SFAS 157 for the reporting of
these nonfinancial assets and liabilities will not have a
material impact on our financial position, results of operations
or cash flows.
In October 2008, the FASB issued FSP
FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset Is Not Active, which clarified the
application of SFAS 157 in inactive markets. This FSP did
not impact our financial position, results of operations or cash
flows.
SFAS 157 also applies to the valuation of our pension and
post-retirement plan assets. The adoption of this standard did
not affect these valuations because SFAS 157 specifically
excluded pension and post-
19
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
retirement assets from its prescribed disclosure provisions.
Accordingly, these plan assets are not included in the tabular
disclosures below. However, in December 2008, the FASB issued
FSP FAS 132(R)-1 Employers Disclosures
about Postretirement Benefit Plan Assets, which will, among
other things, require disclosure about fair value measurements
similar to those required by SFAS 157. This FSP will impact
our annual disclosure requirements beginning in fiscal 2010.
In April 2009, the FASB issued FSP
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments. This FSP requires companies to disclose the
fair value of financial instruments for which it is practicable
to estimate the value and the methods and significant
assumptions used to estimate the fair value. We have adopted the
disclosure requirements of this FSP, which are presented below.
Determining
Fair Value
SFAS 157 defines fair value as the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the
measurement date (exit price). We primarily use quoted market
prices and other observable market pricing information in
valuing our financial assets and liabilities and minimize the
use of unobservable pricing inputs in our measurements.
Prices actively quoted on national exchanges are used to
determine the fair value of most of our assets and liabilities
recorded on our balance sheet at fair value. Within our
nonregulated operations, we utilize a mid-market pricing
convention (the mid-point between the bid and ask prices) as a
practical expedient for determining fair value measurement, as
permitted under SFAS 157. Values derived from these sources
reflect the market in which transactions involving these
financial instruments are executed. We utilize models and other
valuation methods to determine fair value when external sources
are not available. Values are adjusted to reflect the potential
impact of an orderly liquidation of our positions over a
reasonable period of time under then-current market conditions.
We believe the market prices and models used to value these
assets and liabilities represent the best information available
with respect to closing exchange and over-the-counter
quotations, time value and volatility factors underlying the
assets and liabilities.
Fair-value estimates also consider our own creditworthiness and
the creditworthiness of the counterparties involved. Our
counterparties consist primarily of financial institutions and
major energy companies. This concentration of counterparties may
materially impact our exposure to credit risk resulting from
market, economic or regulatory conditions. Recent adverse
developments in the global financial and credit markets have
made it more difficult and more expensive for companies to
access the short-term capital markets, which may negatively
impact the creditworthiness of our counterparties. A continued
tightening of the credit markets could cause more of our
counterparties to fail to perform. We seek to minimize
counterparty credit risk through an evaluation of their
financial condition and credit ratings and the use of collateral
requirements under certain circumstances.
SFAS 157 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value based on
observable and unobservable data. The hierarchy categorizes the
inputs into three levels, with the highest priority given to
unadjusted quoted prices in active markets for identical assets
and liabilities (Level 1) and the lowest priority
given to unobservable inputs (Level 3). The levels of the
hierarchy are described below:
Level 1 Unadjusted quoted prices
in active markets for identical assets or liabilities. An active
market for the asset or liability is defined as a market in
which transactions for the asset or liability occur with
sufficient frequency and volume to provide pricing information
on an ongoing basis. Our Level 1 measurements consist
primarily of exchange-traded financial instruments, gas stored
underground that has been designated as the hedged item in a
fair value hedge and our available-for-sale securities.
Level 2 Pricing inputs other than
quoted prices included in Level 1 that are either directly
or indirectly observable for the asset or liability as of the
reporting date. These inputs are derived principally from, or
corroborated by, observable market data. Our Level 2
measurements primarily consist of non-
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
exchange-traded financial instruments, such as over-the-counter
options and swaps where market data for pricing is observable.
Level 3 Generally unobservable
pricing inputs which are developed based on the best information
available, including our own internal data, in situations where
there is little if any market activity for the asset or
liability at the measurement date. The pricing inputs utilized
reflect what a market participant would use to determine fair
value. Currently, we have no assets or liabilities recorded at
fair value that would qualify for Level 3 reporting.
Quantitative
Disclosures
Financial
Instruments
The classification of our fair value measurements requires
judgment regarding the degree to which market data are
observable or corroborated by observable market data. The
following table summarizes, by level within the fair value
hierarchy, our assets and liabilities that were accounted for at
fair value on a recurring basis as of March 31, 2009. As
required under SFAS 157, assets and liabilities are
categorized in their entirety based on the lowest level of input
that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Netting and
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Cash
|
|
|
March 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Collateral(1)
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
676
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
676
|
|
Natural gas marketing segment
|
|
|
45,770
|
|
|
|
80,564
|
|
|
|
|
|
|
|
(75,558
|
)
|
|
|
50,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
45,770
|
|
|
|
81,240
|
|
|
|
|
|
|
|
(75,558
|
)
|
|
|
51,452
|
|
Hedged portion of gas stored underground
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
62,912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,912
|
|
Pipeline, storage and other
segment(2)
|
|
|
3,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas stored underground
|
|
|
66,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66,568
|
|
Available-for-sale securities
|
|
|
26,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
138,943
|
|
|
$
|
81,240
|
|
|
$
|
|
|
|
$
|
(75,558
|
)
|
|
$
|
144,625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
22,539
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
22,539
|
|
Natural gas marketing segment
|
|
|
117,413
|
|
|
|
41,567
|
|
|
|
|
|
|
|
(154,656
|
)
|
|
|
4,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
117,413
|
|
|
$
|
64,106
|
|
|
$
|
|
|
|
$
|
(154,656
|
)
|
|
$
|
26,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This column reflects adjustments to our gross financial
instrument assets and liabilities to reflect netting permitted
under our master netting agreements and FSP
FIN 39-1.
In addition, as of March 31, 2009, we had
$79.1 million of cash held in margin accounts to
collateralize certain financial instruments. Of this amount,
$71.6 million was used to offset financial instruments in a
liability position. The remaining $7.5 million has been
reflected as a financial instrument asset. |
|
(2) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Fair Value Measures
In addition to the financial instruments above, we have several
nonfinancial assets and liabilities subject to fair value
measures. These assets and liabilities include cash and cash
equivalents, accounts receivable, accounts payable, debt, asset
retirement obligations and pension and post-retirement plan
assets. As noted above, fair value disclosures for asset
retirement obligations and pension and post-retirement plan
assets are not currently effective for us. We record cash and
cash equivalents, accounts receivable, accounts payable and debt
at carrying value. For cash and cash equivalents, accounts
receivable and accounts payable, we consider carrying value to
materially approximate fair value due to the short-term nature
of these assets and liabilities. The fair value of our debt is
determined using a discounted cash flow analysis based upon
borrowing rates currently available to us, the remaining average
maturities and our credit rating. The following table presents
the carrying value and fair value of our debt as of
March 31, 2009:
|
|
|
|
|
|
|
March 31, 2009
|
|
|
(In thousands)
|
|
Carrying Amount
|
|
$
|
2,572,987
|
|
Fair Value
|
|
$
|
2,166,454
|
|
The fair value as of March 31, 2009 was calculated
utilizing discount rates ranging from 6.6 percent to
9.6 percent, remaining average maturities ranging from one
to 26 years, and a credit adjustment of 6.0 percent.
Long-term
debt
Long-term debt at March 31, 2009 and September 30,
2008 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Unsecured 4.00% Senior Notes, due April 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 8.50% Senior Notes, due 2019
|
|
|
450,000
|
|
|
|
|
|
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
|
|
Other term notes due in installments through 2013
|
|
|
684
|
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,572,987
|
|
|
|
2,123,612
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(3,621
|
)
|
|
|
(3,035
|
)
|
Current maturities
|
|
|
(400,225
|
)
|
|
|
(785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,169,141
|
|
|
$
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On March 26, 2009, we closed our Senior Notes Offering. The
effective interest rate on these notes is 8.69 percent,
after giving effect to the settlement of the $450 million
treasury lock discussed in Note 3. Most of the net proceeds
of approximately $446 million were used to redeem our
$400 million 4.00% unsecured senior notes, which, on
March 30, 2009, were called for redemption on
April 30, 2009, prior to their October 2009 maturity. In
connection with the repayment of the $400 million 4.00%
unsecured senior notes, we paid a $6.6 million call premium
in accordance with the terms of the senior notes and accrued
interest of approximately $0.6 million. The remaining net
proceeds will be used for general corporate purposes.
Short-term
debt
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply our customers needs could significantly affect our
borrowing requirements. Our short-term borrowings reach their
highest levels in the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide approximately $1.2 billion of working
capital funding. At March 31, 2009, there was no short-term
debt outstanding. At September 30, 2008, there was
$350.5 million of short-term debt outstanding, comprised of
$330.5 million outstanding under our bank credit facilities
and $20.0 million outstanding under our commercial paper
program. We also use intercompany credit facilities to
supplement the funding provided by these third-party committed
credit facilities. These facilities are described in greater
detail below.
Regulated
Operations
We fund our regulated operations as needed primarily through a
$566.7 million commercial paper program and three committed
revolving credit facilities with third-party lenders that
provide approximately $800 million of working capital
funding. The first facility is a five-year unsecured facility,
expiring December 2011, that bears interest at a base rate
or at a LIBOR-based rate for the applicable interest period,
plus a spread ranging from 0.30 percent to
0.75 percent, based on the Companys credit ratings.
This credit facility serves as a backup liquidity facility for
our commercial paper program. At the time this credit facility
was established, borrowings under this facility were limited to
$600 million. However, in September 2008, the limit on
borrowings was effectively reduced to $566.7 million after
one lender with a 5.55% share of the commitments ceased funding
under the facility. On March 30, 2009, the credit facility
was amended to reflect this reduction. At March 31, 2009,
there were no borrowings under this facility and
$566.7 million was available.
The second facility is a $212.5 million unsecured
364-day
facility expiring October 2009, that bears interest at a base
rate or at a LIBOR-based rate for the applicable interest
period, plus a spread ranging from 1.25 percent to
2.50 percent, based on the Companys credit ratings.
At March 31, 2009, there were no borrowings outstanding
under this facility.
The third facility was an $18 million unsecured facility
that bore interest at a daily negotiated rate, generally based
on the Federal Funds rate plus a variable margin. At
March 31, 2009, there were no borrowings outstanding under
this facility. This facility expired on March 31, 2009 and
was replaced with a $25 million unsecured facility
effective April 1, 2009 that bears interest at a daily
negotiated rate.
The availability of funds under these credit facilities is
subject to conditions specified in the respective credit
agreements, all of which we currently satisfy. These conditions
include our compliance with financial covenants and the
continued accuracy of representations and warranties contained
in these agreements. We are required by the financial covenants
in each of these facilities to maintain, at the end of each
fiscal quarter, a ratio of total debt to total capitalization of
no greater than 70 percent. At March 31, 2009, our
total-debt-to-
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
total-capitalization ratio, as defined, was 56 percent. In
addition, both the interest margin over the Eurodollar rate and
the fee that we pay on unused amounts under each of these
facilities are subject to adjustment depending upon our credit
ratings.
In addition to these third-party facilities, our regulated
operations had a $200 million intercompany revolving credit
facility with AEH. Through December 31, 2008, this facility
bore interest at the one-month LIBOR rate plus
0.20 percent. In January 2009, this facility was replaced
with a new $200 million 364 day-facility that bears
interest at the lower of (i) the one-month LIBOR rate plus
0.45 percent or (ii) the marginal borrowing rate
available to the Company on the date of borrowing. The marginal
borrowing rate is defined as the lower of (i) a rate based
upon the lower of the Prime Rate or the Eurodollar rate under
the five year revolving credit facility or (ii) the lowest
rate outstanding under the commercial paper program. Applicable
state regulatory commissions have approved the new facility
through December 31, 2009. There were no borrowings
outstanding under this facility at March 31, 2009.
Nonregulated
Operations
On December 30, 2008, AEM and the participating banks
amended and restated AEMs former uncommitted credit
facility, primarily to convert the $580 million uncommitted
demand credit facility to a
364-day
$375 million committed revolving credit facility and extend
it to December 29, 2009.
The amended facility also provides the ability for AEM to
increase the borrowing base up to a maximum of $450 million
through an accordion feature, subject to the approval of the
participating banks; adds a swing line loan feature; adjusts the
interest rate on borrowings as discussed below and increases the
fees paid to reflect the facilitys conversion to a
committed facility and current credit market conditions. The
swing line loan feature allows AEM to borrow, on a same day
basis, an amount ranging from $17 million to
$27 million based on the terms of an election within the
agreement. Effective April 1, 2009, the borrowing base was
increased to $450 million as a result of the exercise of
the accordion feature in the facility.
AEM uses this facility primarily to issue letters of credit and,
on a less frequent basis, to borrow funds for gas purchases and
other working capital needs. At AEMs option, borrowings
made under the credit facility are based on a base rate or an
offshore rate, in each case plus an applicable margin. The base
rate is a floating rate equal to the higher of:
(a) 0.50 percent per annum above the latest federal
funds rate; (b) the per annum rate of interest established
by BNP Paribas from time to time as its prime rate
or base rate for U.S. dollar loans; (c) an
offshore rate (based on LIBOR with a one-month interest period)
as in effect from time to time; and (d) the cost of
funds rate based on an average of interest rates reported
by one or more of the lenders to the administrative agent. The
offshore rate is a floating rate equal to the higher of
(a) an offshore rate based upon LIBOR for the applicable
interest period; and (b) a cost of funds rate
referred to above. In the case of both base rate and offshore
rate loans, the applicable margin ranges from 2.250 percent
to 2.625 percent per annum, depending on the excess
tangible net worth of AEM, as defined in the credit facility.
This facility is collateralized by substantially all of the
assets of AEM and is guaranteed by AEH.
At March 31, 2009, there were no borrowings outstanding
under this credit facility. However, at March 31, 2009, AEM
letters of credit totaling $48.4 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 $201.0 million at March 31, 2009.
AEM is required by the financial covenants in this facility to
maintain a ratio of total liabilities to tangible net worth that
does not exceed a maximum of 5 to 1. At March 31, 2009,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 0.83 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$75 million to $112.5 million. As defined in the
financial
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
covenants, at March 31, 2009, AEMs net working
capital was $251.5 million and its tangible net worth was
$271.3 million.
To supplement borrowings under this facility, through
December 31, 2008, AEM had a $200 million intercompany
demand credit facility with AEH, which bore interest at the rate
for AEMs offshore borrowings under its committed credit
facility plus 0.75 percent. Amounts outstanding under this
facility are subordinated to AEMs committed credit
facility. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. A total of
$60.0 million was outstanding under this facility at
March 31, 2009.
Finally, through December 31, 2008, AEH had a
$200 million intercompany demand credit facility with AEC,
which bore interest at the rate for AEMs offshore
borrowings under its committed credit facility plus
0.75 percent. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. Applicable
state regulatory commissions have approved the new facility
through December 31, 2009. There were no borrowings
outstanding under this facility at March 31, 2009.
Shelf
Registration
On March 23, 2009, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$450 million of capacity carried over from our prior shelf
registration statement filed with the SEC in December 2006.
As of March 31, 2009, we had $450 million of
availability remaining under the registration statement after
completing our Senior Notes Offering. However, due to certain
restrictions placed by one state regulatory commission on our
ability to issue securities under the registration statement, we
now have remaining and available for issuance a total of
approximately $300 million of equity securities and
$150 million of subordinated debt securities.
Debt
Covenants
In addition to the financial covenants described above, our debt
instruments contain various covenants that are usual and
customary for debt instruments of these types.
Additionally, our public debt indentures relating to our senior
notes and debentures, as well as our revolving credit
agreements, each contain a default provision that is triggered
if outstanding indebtedness arising out of any other credit
agreements in amounts ranging from in excess of $15 million
to in excess of $100 million becomes due by acceleration or
is not paid at maturity.
Further, AEMs credit agreement contains a cross-default
provision whereby AEM would be in default if it defaults on
other indebtedness, as defined, by at least $250 thousand in the
aggregate.
Finally, AEMs credit agreement contains a provision that
would limit the amount of credit available if Atmos Energy were
downgraded below an S&P rating of BBB and a Moodys
rating of Baa2. We have no other triggering events in our debt
instruments that are tied to changes in specified credit ratings
or stock price, nor have we entered into any transactions that
would require us to issue equity, based on our credit rating or
other triggering events.
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We were in compliance with all of our debt covenants as of
March 31, 2009. If we were unable to comply with our debt
covenants, we would likely be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions.
Basic and diluted earnings per share for the three and six
months ended March 31, 2009 and 2008 are calculated as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per share weighted
average common shares
|
|
|
90,895
|
|
|
|
89,314
|
|
|
|
90,637
|
|
|
|
89,133
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
639
|
|
|
|
583
|
|
|
|
639
|
|
|
|
585
|
|
Stock options
|
|
|
33
|
|
|
|
93
|
|
|
|
35
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per share weighted
average common shares
|
|
|
91,567
|
|
|
|
89,990
|
|
|
|
91,311
|
|
|
|
89,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share basic
|
|
$
|
1.42
|
|
|
$
|
1.25
|
|
|
$
|
2.26
|
|
|
$
|
2.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share diluted
|
|
$
|
1.41
|
|
|
$
|
1.24
|
|
|
$
|
2.24
|
|
|
$
|
2.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were approximately 260,000 out-of-the-money stock options
excluded from the computation of diluted earnings per share for
the three and six months ended March 31, 2009. There were
no out-of-the-money
stock options excluded from the computation of diluted earnings
per share for the three and six months ended March 31, 2008
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 six
months ended March 31, 2009 and 2008 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 March 31
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,703
|
|
|
$
|
3,878
|
|
|
$
|
2,946
|
|
|
$
|
3,341
|
|
Interest cost
|
|
|
7,554
|
|
|
|
6,736
|
|
|
|
3,520
|
|
|
|
2,912
|
|
Expected return on assets
|
|
|
(6,238
|
)
|
|
|
(6,311
|
)
|
|
|
(573
|
)
|
|
|
(715
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
378
|
|
|
|
378
|
|
Amortization of prior service cost
|
|
|
(183
|
)
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
Amortization of actuarial loss
|
|
|
955
|
|
|
|
1,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
5,791
|
|
|
$
|
6,058
|
|
|
$
|
6,271
|
|
|
$
|
5,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
7,406
|
|
|
$
|
7,756
|
|
|
$
|
5,892
|
|
|
$
|
6,682
|
|
Interest cost
|
|
|
15,108
|
|
|
|
13,472
|
|
|
|
7,040
|
|
|
|
5,824
|
|
Expected return on assets
|
|
|
(12,476
|
)
|
|
|
(12,621
|
)
|
|
|
(1,146
|
)
|
|
|
(1,430
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
756
|
|
|
|
756
|
|
Amortization of prior service cost
|
|
|
(366
|
)
|
|
|
(342
|
)
|
|
|
|
|
|
|
|
|
Amortization of actuarial loss
|
|
|
1,910
|
|
|
|
3,852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
11,582
|
|
|
$
|
12,117
|
|
|
$
|
12,542
|
|
|
$
|
11,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three and six months ended March 31, 2009 and 2008
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Discount rate
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
|
|
7.57
|
%
|
|
|
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
|
%
|
|
|
5.00
|
%
|
The discount rate used to compute the present value of a
plans liabilities generally is based on rates of
high-grade corporate bonds with maturities similar to the
average period over which the benefits will be paid. Generally,
our funding policy has been to contribute annually an amount in
accordance with the requirements of the Employee Retirement
Income Security Act of 1974. In accordance with the Pension
Protection Act of 2006 (PPA), we determined the funded status of
our plans as of January 1, 2009. Based upon this valuation,
we expect we will be required to contribute less than
$25 million to our pension plans by September 15, 2009.
We contributed $5.2 million to our other post-retirement
benefit plans during the six months ended March 31, 2009.
We expect to contribute a total of approximately
$10 million to these plans during fiscal 2009.
|
|
8.
|
Commitments
and Contingencies
|
Litigation
and Environmental Matters
With respect to the specific litigation and
environmental-related matters or claims that were disclosed in
Note 12 to the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008, there were no
material changes in the status of such litigation and
environmental-related matters or claims during the six months
ended March 31, 2009. 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.
27
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Purchase
Commitments
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At March 31, 2009, AEM was committed to
purchase 97.6 Bcf within one year, 32.5 Bcf within one
to three years and 1.0 Bcf after three years under indexed
contracts. AEM is committed to purchase 1.3 Bcf within one
year under fixed price contracts with prices ranging from $2.59
to $7.68 per Mcf. Purchases under these contracts totaled
$431.5 million and $860.3 million for the three months
ended March 31, 2009 and 2008 and $959.0 million and
$1,432.3 million for the six months ended March 31,
2009 and 2008.
Our natural gas distribution divisions, except for our Mid-Tex
Division, maintain supply contracts with several vendors that
generally cover a period of up to one year. Commitments for
estimated base gas volumes are established under these contracts
on a monthly basis at contractually negotiated prices.
Commitments for incremental daily purchases are made as
necessary during the month in accordance with the terms of the
individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
and fixed prices. The estimated commitments under these
contracts as of March 31, 2009 are as follows (in
thousands):
|
|
|
|
|
2009
|
|
$
|
40,033
|
|
2010
|
|
|
53,425
|
|
2011
|
|
|
5,245
|
|
2012
|
|
|
6,769
|
|
2013
|
|
|
7,453
|
|
Thereafter
|
|
|
2,571
|
|
|
|
|
|
|
|
|
$
|
115,496
|
|
|
|
|
|
|
Regulatory
Matters
As previously described in Note 12 to the consolidated
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008, in December
2007, the Company received data requests from the Division of
Investigations of the Office of Enforcement of the Federal
Energy Regulatory Commission (the Commission) in
connection with its investigation into possible violations of
the Commissions posting and competitive bidding
regulations for pre-arranged released firm capacity on natural
gas pipelines.
After responding to two sets of data requests received from the
Commission, the Commission agreed to allow us to conduct our own
internal investigation into compliance with the
Commissions rules. During the second quarter, we completed
our internal investigation and submitted the results to the
Commission. During our investigation, we identified certain
transactions that could possibly be considered non-compliant,
and we continue to fully cooperate with the Commission as we
work to resolve this matter. We have accrued what we believe is
an adequate amount for the anticipated resolution of this
proceeding. While the ultimate resolution of this investigation
cannot be predicted with certainty, we believe that the final
outcome will not have a material adverse effect on our financial
condition, results of operations or cash flows.
As of March 31, 2009, rate cases were in progress in our
City of Dallas and Virginia service areas and annual rate filing
mechanisms were in progress in our Mid-Tex, West Texas,
Louisiana and Atmos Pipeline Texas divisions. These
regulatory proceedings are discussed in further detail in
Managements Discussion and Analysis Recent
Ratemaking Developments.
28
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
9.
|
Concentration
of Credit Risk
|
Information regarding our concentration of credit risk is
disclosed in Note 14 to the financial statements in our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. During the
six months ended March 31, 2009, there were no material
changes in our concentration of credit risk.
Atmos Energy and our subsidiaries are engaged primarily in the
regulated natural gas distribution, transmission and storage
business as well as other nonregulated businesses. We distribute
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, 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 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.
|
|
|
|
The pipeline, storage and other segment, which includes
our nonregulated natural gas transmission and storage services.
|
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in 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, 2008. We evaluate
performance based on net income or loss of the respective
operating units.
29
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income statements for the three and six month periods ended
March 31, 2009 and 2008 by segment are presented in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from
external parties
|
|
$
|
1,230,196
|
|
|
$
|
32,097
|
|
|
$
|
549,136
|
|
|
$
|
9,977
|
|
|
$
|
|
|
|
$
|
1,821,406
|
|
Intersegment revenues
|
|
|
224
|
|
|
|
27,137
|
|
|
|
159,522
|
|
|
|
2,295
|
|
|
|
(189,178
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,230,420
|
|
|
|
59,234
|
|
|
|
708,658
|
|
|
|
12,272
|
|
|
|
(189,178
|
)
|
|
|
1,821,406
|
|
Purchased gas cost
|
|
|
863,340
|
|
|
|
|
|
|
|
685,114
|
|
|
|
1,656
|
|
|
|
(188,755
|
)
|
|
|
1,361,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
367,080
|
|
|
|
59,234
|
|
|
|
23,544
|
|
|
|
10,616
|
|
|
|
(423
|
)
|
|
|
460,051
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
90,710
|
|
|
|
17,327
|
|
|
|
12,323
|
|
|
|
1,889
|
|
|
|
(509
|
)
|
|
|
121,740
|
|
Depreciation and amortization
|
|
|
47,541
|
|
|
|
5,006
|
|
|
|
396
|
|
|
|
507
|
|
|
|
|
|
|
|
53,450
|
|
Taxes, other than income
|
|
|
55,101
|
|
|
|
2,572
|
|
|
|
446
|
|
|
|
195
|
|
|
|
|
|
|
|
58,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
193,352
|
|
|
|
24,905
|
|
|
|
13,165
|
|
|
|
2,591
|
|
|
|
(509
|
)
|
|
|
233,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
173,728
|
|
|
|
34,329
|
|
|
|
10,379
|
|
|
|
8,025
|
|
|
|
86
|
|
|
|
226,547
|
|
Miscellaneous income (expense)
|
|
|
835
|
|
|
|
283
|
|
|
|
118
|
|
|
|
2,060
|
|
|
|
(4,861
|
)
|
|
|
(1,565
|
)
|
Interest charges
|
|
|
28,821
|
|
|
|
7,349
|
|
|
|
3,461
|
|
|
|
677
|
|
|
|
(4,775
|
)
|
|
|
35,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
145,742
|
|
|
|
27,263
|
|
|
|
7,036
|
|
|
|
9,408
|
|
|
|
|
|
|
|
189,449
|
|
Income tax expense
|
|
|
44,166
|
|
|
|
7,798
|
|
|
|
3,688
|
|
|
|
4,794
|
|
|
|
|
|
|
|
60,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
101,576
|
|
|
$
|
19,465
|
|
|
$
|
3,348
|
|
|
$
|
4,614
|
|
|
$
|
|
|
|
$
|
129,003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
84,618
|
|
|
$
|
28,303
|
|
|
$
|
88
|
|
|
$
|
954
|
|
|
$
|
|
|
|
$
|
113,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
1,521,636
|
|
|
$
|
22,830
|
|
|
$
|
931,990
|
|
|
$
|
7,529
|
|
|
$
|
|
|
|
$
|
2,483,985
|
|
Intersegment revenues
|
|
|
220
|
|
|
|
28,610
|
|
|
|
196,663
|
|
|
|
2,493
|
|
|
|
(227,986
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,521,856
|
|
|
|
51,440
|
|
|
|
1,128,653
|
|
|
|
10,022
|
|
|
|
(227,986
|
)
|
|
|
2,483,985
|
|
Purchased gas cost
|
|
|
1,164,332
|
|
|
|
|
|
|
|
1,112,321
|
|
|
|
338
|
|
|
|
(227,400
|
)
|
|
|
2,049,591
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
357,524
|
|
|
|
51,440
|
|
|
|
16,332
|
|
|
|
9,684
|
|
|
|
(586
|
)
|
|
|
434,394
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
98,578
|
|
|
|
15,086
|
|
|
|
5,525
|
|
|
|
1,536
|
|
|
|
(672
|
)
|
|
|
120,053
|
|
Depreciation and amortization
|
|
|
43,130
|
|
|
|
4,907
|
|
|
|
374
|
|
|
|
379
|
|
|
|
|
|
|
|
48,790
|
|
Taxes, other than income
|
|
|
52,304
|
|
|
|
1,385
|
|
|
|
407
|
|
|
|
312
|
|
|
|
|
|
|
|
54,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
194,012
|
|
|
|
21,378
|
|
|
|
6,306
|
|
|
|
2,227
|
|
|
|
(672
|
)
|
|
|
223,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
163,512
|
|
|
|
30,062
|
|
|
|
10,026
|
|
|
|
7,457
|
|
|
|
86
|
|
|
|
211,143
|
|
Miscellaneous income
|
|
|
3,670
|
|
|
|
209
|
|
|
|
602
|
|
|
|
1,942
|
|
|
|
(4,956
|
)
|
|
|
1,467
|
|
Interest charges
|
|
|
29,084
|
|
|
|
6,776
|
|
|
|
2,002
|
|
|
|
524
|
|
|
|
(4,870
|
)
|
|
|
33,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
138,098
|
|
|
|
23,495
|
|
|
|
8,626
|
|
|
|
8,875
|
|
|
|
|
|
|
|
179,094
|
|
Income tax expense
|
|
|
52,442
|
|
|
|
8,271
|
|
|
|
3,347
|
|
|
|
3,500
|
|
|
|
|
|
|
|
67,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
85,656
|
|
|
$
|
15,224
|
|
|
$
|
5,279
|
|
|
$
|
5,375
|
|
|
$
|
|
|
|
$
|
111,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
89,671
|
|
|
$
|
13,700
|
|
|
$
|
38
|
|
|
$
|
1,158
|
|
|
$
|
|
|
|
$
|
104,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,285,968
|
|
|
$
|
62,319
|
|
|
$
|
1,165,980
|
|
|
$
|
23,471
|
|
|
$
|
|
|
|
$
|
3,537,738
|
|
Intersegment revenues
|
|
|
420
|
|
|
|
51,597
|
|
|
|
330,173
|
|
|
|
5,249
|
|
|
|
(387,439
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,286,388
|
|
|
|
113,916
|
|
|
|
1,496,153
|
|
|
|
28,720
|
|
|
|
(387,439
|
)
|
|
|
3,537,738
|
|
Purchased gas cost
|
|
|
1,620,924
|
|
|
|
|
|
|
|
1,442,586
|
|
|
|
5,559
|
|
|
|
(386,594
|
)
|
|
|
2,682,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
665,464
|
|
|
|
113,916
|
|
|
|
53,567
|
|
|
|
23,161
|
|
|
|
(845
|
)
|
|
|
855,263
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
188,704
|
|
|
|
44,896
|
|
|
|
20,839
|
|
|
|
3,073
|
|
|
|
(1,017
|
)
|
|
|
256,495
|
|
Depreciation and amortization
|
|
|
94,680
|
|
|
|
9,961
|
|
|
|
797
|
|
|
|
1,138
|
|
|
|
|
|
|
|
106,576
|
|
Taxes, other than income
|
|
|
95,847
|
|
|
|
5,360
|
|
|
|
1,039
|
|
|
|
205
|
|
|
|
|
|
|
|
102,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
379,231
|
|
|
|
60,217
|
|
|
|
22,675
|
|
|
|
4,416
|
|
|
|
(1,017
|
)
|
|
|
465,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
286,233
|
|
|
|
53,699
|
|
|
|
30,892
|
|
|
|
18,745
|
|
|
|
172
|
|
|
|
389,741
|
|
Miscellaneous income (expense)
|
|
|
3,956
|
|
|
|
1,098
|
|
|
|
419
|
|
|
|
4,221
|
|
|
|
(11,560
|
)
|
|
|
(1,866
|
)
|
Interest charges
|
|
|
61,708
|
|
|
|
15,428
|
|
|
|
7,363
|
|
|
|
1,413
|
|
|
|
(11,388
|
)
|
|
|
74,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
228,481
|
|
|
|
39,369
|
|
|
|
23,948
|
|
|
|
21,553
|
|
|
|
|
|
|
|
313,351
|
|
Income tax expense
|
|
|
76,772
|
|
|
|
12,243
|
|
|
|
10,025
|
|
|
|
9,345
|
|
|
|
|
|
|
|
108,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
151,709
|
|
|
$
|
27,126
|
|
|
$
|
13,923
|
|
|
$
|
12,208
|
|
|
$
|
|
|
|
$
|
204,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
173,621
|
|
|
$
|
33,363
|
|
|
$
|
117
|
|
|
$
|
14,229
|
|
|
$
|
|
|
|
$
|
221,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended March 31, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,449,665
|
|
|
$
|
45,267
|
|
|
$
|
1,634,712
|
|
|
$
|
11,851
|
|
|
$
|
|
|
|
$
|
4,141,495
|
|
Intersegment revenues
|
|
|
368
|
|
|
|
51,219
|
|
|
|
334,658
|
|
|
|
4,898
|
|
|
|
(391,143
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,450,033
|
|
|
|
96,486
|
|
|
|
1,969,370
|
|
|
|
16,749
|
|
|
|
(391,143
|
)
|
|
|
4,141,495
|
|
Purchased gas cost
|
|
|
1,819,309
|
|
|
|
|
|
|
|
1,907,075
|
|
|
|
1,067
|
|
|
|
(389,988
|
)
|
|
|
3,337,463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
630,724
|
|
|
|
96,486
|
|
|
|
62,295
|
|
|
|
15,682
|
|
|
|
(1,155
|
)
|
|
|
804,032
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
195,825
|
|
|
|
30,518
|
|
|
|
13,402
|
|
|
|
2,824
|
|
|
|
(1,327
|
)
|
|
|
241,242
|
|
Depreciation and amortization
|
|
|
85,962
|
|
|
|
9,823
|
|
|
|
761
|
|
|
|
757
|
|
|
|
|
|
|
|
97,303
|
|
Taxes, other than income
|
|
|
87,922
|
|
|
|
3,829
|
|
|
|
3,407
|
|
|
|
677
|
|
|
|
|
|
|
|
95,835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
369,709
|
|
|
|
44,170
|
|
|
|
17,570
|
|
|
|
4,258
|
|
|
|
(1,327
|
)
|
|
|
434,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
261,015
|
|
|
|
52,316
|
|
|
|
44,725
|
|
|
|
11,424
|
|
|
|
172
|
|
|
|
369,652
|
|
Miscellaneous income
|
|
|
4,146
|
|
|
|
383
|
|
|
|
1,398
|
|
|
|
3,970
|
|
|
|
(8,523
|
)
|
|
|
1,374
|
|
Interest charges
|
|
|
60,298
|
|
|
|
13,847
|
|
|
|
3,316
|
|
|
|
1,223
|
|
|
|
(8,351
|
)
|
|
|
70,333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
204,863
|
|
|
|
38,852
|
|
|
|
42,807
|
|
|
|
14,171
|
|
|
|
|
|
|
|
300,693
|
|
Income tax expense
|
|
|
79,043
|
|
|
|
13,781
|
|
|
|
16,928
|
|
|
|
5,604
|
|
|
|
|
|
|
|
115,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
125,820
|
|
|
$
|
25,071
|
|
|
$
|
25,879
|
|
|
$
|
8,567
|
|
|
$
|
|
|
|
$
|
185,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
173,984
|
|
|
$
|
22,082
|
|
|
$
|
69
|
|
|
$
|
2,587
|
|
|
$
|
|
|
|
$
|
198,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at March 31, 2009 and
September 30, 2008 by segment is presented in the following
tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,577,546
|
|
|
$
|
608,118
|
|
|
$
|
7,312
|
|
|
$
|
70,216
|
|
|
$
|
|
|
|
$
|
4,263,192
|
|
Investment in subsidiaries
|
|
|
484,117
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(482,021
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
379,391
|
|
|
|
|
|
|
|
86,143
|
|
|
|
16,551
|
|
|
|
|
|
|
|
482,085
|
|
Assets from risk management activities
|
|
|
676
|
|
|
|
|
|
|
|
42,266
|
|
|
|
2,394
|
|
|
|
(3,623
|
)
|
|
|
41,713
|
|
Other current assets
|
|
|
671,993
|
|
|
|
16,614
|
|
|
|
265,457
|
|
|
|
77,428
|
|
|
|
(76,735
|
)
|
|
|
954,757
|
|
Intercompany receivables
|
|
|
504,887
|
|
|
|
|
|
|
|
|
|
|
|
147,783
|
|
|
|
(652,670
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,556,947
|
|
|
|
16,614
|
|
|
|
393,866
|
|
|
|
244,156
|
|
|
|
(733,028
|
)
|
|
|
1,478,555
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
1,774
|
|
|
|
|
|
|
|
|
|
|
|
1,774
|
|
Goodwill
|
|
|
569,920
|
|
|
|
132,367
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
736,998
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
9,739
|
|
|
|
|
|
|
|
|
|
|
|
9,739
|
|
Deferred charges and other assets
|
|
|
166,610
|
|
|
|
7,924
|
|
|
|
873
|
|
|
|
20,096
|
|
|
|
|
|
|
|
195,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,355,140
|
|
|
$
|
765,023
|
|
|
$
|
435,750
|
|
|
$
|
344,897
|
|
|
$
|
(1,215,049
|
)
|
|
$
|
6,685,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,178,494
|
|
|
$
|
157,270
|
|
|
$
|
75,451
|
|
|
$
|
251,396
|
|
|
$
|
(484,117
|
)
|
|
$
|
2,178,494
|
|
Long-term debt
|
|
|
2,168,683
|
|
|
|
|
|
|
|
|
|
|
|
458
|
|
|
|
|
|
|
|
2,169,141
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,347,177
|
|
|
|
157,270
|
|
|
|
75,451
|
|
|
|
251,854
|
|
|
|
(484,117
|
)
|
|
|
4,347,635
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
400,000
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
400,225
|
|
Short-term debt
|
|
|
|
|
|
|
|
|
|
|
60,000
|
|
|
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
Liabilities from risk management activities
|
|
|
22,535
|
|
|
|
|
|
|
|
6,734
|
|
|
|
1,200
|
|
|
|
(3,623
|
)
|
|
|
26,846
|
|
Other current liabilities
|
|
|
586,656
|
|
|
|
6,850
|
|
|
|
203,044
|
|
|
|
76,973
|
|
|
|
(14,527
|
)
|
|
|
858,996
|
|
Intercompany payables
|
|
|
|
|
|
|
525,249
|
|
|
|
127,421
|
|
|
|
|
|
|
|
(652,670
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,009,191
|
|
|
|
532,099
|
|
|
|
397,199
|
|
|
|
78,398
|
|
|
|
(730,820
|
)
|
|
|
1,286,067
|
|
Deferred income taxes
|
|
|
422,381
|
|
|
|
71,643
|
|
|
|
(37,586
|
)
|
|
|
10,542
|
|
|
|
(112
|
)
|
|
|
466,868
|
|
Noncurrent liabilities from risk management activities
|
|
|
4
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Regulatory cost of removal obligation
|
|
|
313,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
313,486
|
|
Deferred credits and other liabilities
|
|
|
262,901
|
|
|
|
4,011
|
|
|
|
673
|
|
|
|
4,103
|
|
|
|
|
|
|
|
271,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,355,140
|
|
|
$
|
765,023
|
|
|
$
|
435,750
|
|
|
$
|
344,897
|
|
|
$
|
(1,215,049
|
)
|
|
$
|
6,685,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 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
|
|
$
|
3,483,556
|
|
|
$
|
585,160
|
|
|
$
|
7,520
|
|
|
$
|
60,623
|
|
|
$
|
|
|
|
$
|
4,136,859
|
|
Investment in subsidiaries
|
|
|
463,158
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(461,062
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
30,878
|
|
|
|
|
|
|
|
9,120
|
|
|
|
6,719
|
|
|
|
|
|
|
|
46,717
|
|
Assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
69,008
|
|
|
|
20,239
|
|
|
|
(20,956
|
)
|
|
|
68,291
|
|
Other current assets
|
|
|
774,933
|
|
|
|
18,396
|
|
|
|
411,648
|
|
|
|
56,791
|
|
|
|
(91,672
|
)
|
|
|
1,170,096
|
|
Intercompany receivables
|
|
|
578,833
|
|
|
|
|
|
|
|
|
|
|
|
135,795
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,384,644
|
|
|
|
18,396
|
|
|
|
489,776
|
|
|
|
219,544
|
|
|
|
(827,256
|
)
|
|
|
1,285,104
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
Goodwill
|
|
|
569,920
|
|
|
|
132,367
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
736,998
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
Deferred charges and other assets
|
|
|
195,985
|
|
|
|
11,212
|
|
|
|
1,182
|
|
|
|
11,798
|
|
|
|
|
|
|
|
220,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,052,492
|
|
|
$
|
130,144
|
|
|
$
|
114,559
|
|
|
$
|
218,455
|
|
|
$
|
(463,158
|
)
|
|
$
|
2,052,492
|
|
Long-term debt
|
|
|
2,119,267
|
|
|
|
|
|
|
|
|
|
|
|
525
|
|
|
|
|
|
|
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,171,759
|
|
|
|
130,144
|
|
|
|
114,559
|
|
|
|
218,980
|
|
|
|
(463,158
|
)
|
|
|
4,172,284
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
785
|
|
|
|
|
|
|
|
785
|
|
Short-term debt
|
|
|
385,592
|
|
|
|
|
|
|
|
6,500
|
|
|
|
|
|
|
|
(41,550
|
)
|
|
|
350,542
|
|
Liabilities from risk management activities
|
|
|
58,566
|
|
|
|
|
|
|
|
20,688
|
|
|
|
616
|
|
|
|
(20,956
|
)
|
|
|
58,914
|
|
Other current liabilities
|
|
|
538,777
|
|
|
|
7,053
|
|
|
|
236,217
|
|
|
|
62,796
|
|
|
|
(47,997
|
)
|
|
|
796,846
|
|
Intercompany payables
|
|
|
|
|
|
|
543,384
|
|
|
|
171,244
|
|
|
|
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
982,935
|
|
|
|
550,437
|
|
|
|
434,649
|
|
|
|
64,197
|
|
|
|
(825,131
|
)
|
|
|
1,207,087
|
|
Deferred income taxes
|
|
|
384,860
|
|
|
|
62,720
|
|
|
|
(21,936
|
)
|
|
|
15,687
|
|
|
|
(29
|
)
|
|
|
441,302
|
|
Noncurrent liabilities from risk management activities
|
|
|
5,111
|
|
|
|
|
|
|
|
258
|
|
|
|
|
|
|
|
|
|
|
|
5,369
|
|
Regulatory cost of removal obligation
|
|
|
298,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
298,645
|
|
Deferred credits and other liabilities
|
|
|
253,953
|
|
|
|
3,834
|
|
|
|
695
|
|
|
|
3,530
|
|
|
|
|
|
|
|
262,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of March 31, 2009, the related
condensed consolidated statements of income for the three-month
and six-month periods ended March 31, 2009 and 2008, and
the condensed consolidated statements of cash flows for the
six-month
periods ended March 31, 2009 and 2008. 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, 2008, 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 18, 2008, 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, 2008, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Dallas, Texas
April 30, 2009
36
|
|
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, 2008.
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, 2008, include the
following: our ability to continue to access the credit markets
to satisfy our liquidity requirements; the impact of recent
economic conditions on our customers; increased costs of
providing pension and postretirement health care benefits and
increased funding requirements; market risks beyond our control
affecting our risk management activities including market
liquidity, commodity price volatility, increasing interest rates
and counterparty creditworthiness; regulatory trends and
decisions, including the impact of rate proceedings before
various state regulatory commissions; increased federal
regulatory oversight and potential penalties; the impact of
environmental regulations on our business; the concentration of
our distribution, pipeline and storage operations in Texas;
adverse weather conditions; the effects of inflation and changes
in the availability and price of natural gas; the
capital-intensive nature of our gas distribution business;
increased competition from energy suppliers and alternative
forms of energy; the inherent hazards and risks involved in
operating our gas distribution business, natural disasters,
terrorist activities or other events; and other risks and
uncertainties discussed herein, all of which are difficult to
predict and many of which are beyond our control. Accordingly,
while we believe these forward-looking statements to be
reasonable, there can be no assurance that they will approximate
actual experience or that the expectations derived from them
will be realized. Further, we undertake no obligation to update
or revise any of our forward-looking statements whether as a
result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the
regulated natural gas distribution and transportation and
storage businesses as well as other nonregulated natural gas
businesses. We distribute natural gas through sales and
transportation arrangements to 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.
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,
|
37
|
|
|
|
|
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 fiscal year ended September 30, 2008 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 quarterly by the
Audit Committee. There were no significant changes to these
critical accounting policies during the six months ended
March 31, 2009.
RESULTS
OF OPERATIONS
The following table presents our consolidated financial
highlights for the three and six months ended March 31,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
$
|
1,821,406
|
|
|
$
|
2,483,985
|
|
|
$
|
3,537,738
|
|
|
$
|
4,141,495
|
|
Gross profit
|
|
|
460,051
|
|
|
|
434,394
|
|
|
|
855,263
|
|
|
|
804,032
|
|
Operating expenses
|
|
|
233,504
|
|
|
|
223,251
|
|
|
|
465,522
|
|
|
|
434,380
|
|
Operating income
|
|
|
226,547
|
|
|
|
211,143
|
|
|
|
389,741
|
|
|
|
369,652
|
|
Miscellaneous income (expense)
|
|
|
(1,565
|
)
|
|
|
1,467
|
|
|
|
(1,866
|
)
|
|
|
1,374
|
|
Interest charges
|
|
|
35,533
|
|
|
|
33,516
|
|
|
|
74,524
|
|
|
|
70,333
|
|
Income before income taxes
|
|
|
189,449
|
|
|
|
179,094
|
|
|
|
313,351
|
|
|
|
300,693
|
|
Income tax expense
|
|
|
60,446
|
|
|
|
67,560
|
|
|
|
108,385
|
|
|
|
115,356
|
|
Net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
Diluted net income per share
|
|
$
|
1.41
|
|
|
$
|
1.24
|
|
|
$
|
2.24
|
|
|
$
|
2.06
|
|
38
Our consolidated net income during the three and six months
ended March 31, 2009 and 2008 was earned in each of our
business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
101,576
|
|
|
$
|
85,656
|
|
|
$
|
15,920
|
|
Regulated transmission and storage segment
|
|
|
19,465
|
|
|
|
15,224
|
|
|
|
4,241
|
|
Natural gas marketing segment
|
|
|
3,348
|
|
|
|
5,279
|
|
|
|
(1,931
|
)
|
Pipeline, storage and other segment
|
|
|
4,614
|
|
|
|
5,375
|
|
|
|
(761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
$
|
17,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
151,709
|
|
|
$
|
125,820
|
|
|
$
|
25,889
|
|
Regulated transmission and storage segment
|
|
|
27,126
|
|
|
|
25,071
|
|
|
|
2,055
|
|
Natural gas marketing segment
|
|
|
13,923
|
|
|
|
25,879
|
|
|
|
(11,956
|
)
|
Pipeline, storage and other segment
|
|
|
12,208
|
|
|
|
8,567
|
|
|
|
3,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
|
$
|
19,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables segregate our consolidated net income and
diluted earnings per share between our regulated and
nonregulated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
121,041
|
|
|
$
|
100,880
|
|
|
$
|
20,161
|
|
Nonregulated operations
|
|
|
7,962
|
|
|
|
10,654
|
|
|
|
(2,692
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
129,003
|
|
|
$
|
111,534
|
|
|
$
|
17,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.32
|
|
|
$
|
1.12
|
|
|
$
|
0.20
|
|
Diluted EPS from nonregulated operations
|
|
|
0.09
|
|
|
|
0.12
|
|
|
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
1.41
|
|
|
$
|
1.24
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
178,835
|
|
|
$
|
150,891
|
|
|
$
|
27,944
|
|
Nonregulated operations
|
|
|
26,131
|
|
|
|
34,446
|
|
|
|
(8,315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
204,966
|
|
|
$
|
185,337
|
|
|
$
|
19,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.96
|
|
|
$
|
1.68
|
|
|
$
|
0.28
|
|
Diluted EPS from nonregulated operations
|
|
|
0.28
|
|
|
|
0.38
|
|
|
|
(0.10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
2.24
|
|
|
$
|
2.06
|
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
The following summarizes the results of our operations and other
significant events for the six months ended March 31, 2009:
|
|
|
|
|
Regulated operations generated 87 percent of our net income
during the six months ended March 31, 2009 compared to
81 percent during the six months ended March 31, 2008.
The $27.9 million increase in our regulated operations net
income primarily reflects favorable ratemaking activity coupled
with a one-time tax benefit discussed below.
|
|
|
|
Nonregulated operations contributed 13 percent of net
income during the six months ended March 31, 2009 compared
to 19 percent during the six months ended March 31,
2008. The $8.3 million decrease in our nonregulated
operations net income primarily reflects a decrease in
unrealized margins and an increase in operating expenses
partially offset by favorable asset optimization margins.
|
|
|
|
For the six months ended March 31, 2009, we generated
$614.6 million in operating cash flow compared with
$479.2 million for the six months ended March 31,
2008, primarily reflecting the favorable impact on our working
capital due to the decline in natural gas prices in the current
year compared to the prior-year period and the favorable timing
of the recovery of gas costs.
|
|
|
|
On March 23, 2009, we filed a $900 million shelf
registration statement with the Securities and Exchange
Commission (SEC) that replaced our previously existing shelf
registration statement. On March 26, 2009, we completed an
offering of $450 million unsecured 8.50% senior notes
and received net proceeds of approximately $446 million.
Most of the net proceeds received were used to repay our
$400 million unsecured 4.00% senior notes, which were
called on March 30, 2009 for redemption on April 30,
2009.
|
|
|
|
Quarter-to-date
and
year-to-date
results were favorably impacted by a one-time tax benefit of
$11.3 million, or $0.12 per diluted share. The benefit
arose during the quarter when we updated the tax rates used to
record our deferred taxes. This benefit increased natural gas
distribution net income by $10.5 million and regulated
transmission and storage income by $1.7 million. However,
net income for the natural gas marketing and pipeline, storage
and other segments net income were reduced by
$0.3 million and $0.6 million.
|
Three
Months Ended March 31, 2009 compared with Three Months
Ended March 31, 2008
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
|
40
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. Prior to January 1,
2009, 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 could 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. Beginning January 1, 2009, changes in
our franchise fee agreements in our Mid-Tex Division became
effective which should significantly reduce the impact of this
timing difference on a prospective basis. However, this timing
difference still occurs for gross receipts taxes.
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.
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the three months ended March 31,
2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
367,080
|
|
|
$
|
357,524
|
|
|
$
|
9,556
|
|
Operating expenses
|
|
|
193,352
|
|
|
|
194,012
|
|
|
|
(660
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
173,728
|
|
|
|
163,512
|
|
|
|
10,216
|
|
Miscellaneous income
|
|
|
835
|
|
|
|
3,670
|
|
|
|
(2,835
|
)
|
Interest charges
|
|
|
28,821
|
|
|
|
29,084
|
|
|
|
(263
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
145,742
|
|
|
|
138,098
|
|
|
|
7,644
|
|
Income tax expense
|
|
|
44,166
|
|
|
|
52,442
|
|
|
|
(8,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
101,576
|
|
|
$
|
85,656
|
|
|
$
|
15,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales
volumes MMcf
|
|
|
121,560
|
|
|
|
135,568
|
|
|
|
(14,008
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
35,061
|
|
|
|
39,730
|
|
|
|
(4,669
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
156,621
|
|
|
|
175,298
|
|
|
|
(18,677
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.48
|
|
|
$
|
0.44
|
|
|
$
|
0.04
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
7.10
|
|
|
$
|
8.59
|
|
|
$
|
(1.49
|
)
|
41
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the three months ended March 31, 2009 and 2008. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
80,374
|
|
|
$
|
72,479
|
|
|
$
|
7,895
|
|
Kentucky/Mid-States
|
|
|
27,404
|
|
|
|
29,875
|
|
|
|
(2,471
|
)
|
Louisiana
|
|
|
19,782
|
|
|
|
19,236
|
|
|
|
546
|
|
West Texas
|
|
|
14,806
|
|
|
|
8,919
|
|
|
|
5,887
|
|
Mississippi
|
|
|
16,771
|
|
|
|
16,514
|
|
|
|
257
|
|
Colorado-Kansas
|
|
|
13,623
|
|
|
|
15,536
|
|
|
|
(1,913
|
)
|
Other
|
|
|
968
|
|
|
|
953
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
173,728
|
|
|
$
|
163,512
|
|
|
$
|
10,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $9.6 million increase in natural gas distribution gross
profit primarily reflects a net $21.9 million increase in
rates. The net increase in rates was attributable primarily to
the Mid-Tex Division, which increased $16.5 million as a
result of the implementation of its 2008 Rate Review Mechanism
(RRM) filing with all incorporated cities in the division other
than the City of Dallas (the Settled Cities) and rate
adjustments for customers in the City of Dallas. The current
year period also reflects a $5.4 million increase in rate
adjustments primarily in Georgia, Louisiana and West Texas. The
increase also reflects the reversal of a $7.0 million
accrual for estimated unrecoverable gas costs recorded in a
prior year. These increases in gross profit were partially
offset by a $13.5 million decrease as a result of an
11 percent decrease in distribution throughput, primarily
associated with lower residential and commercial consumption and
warmer weather in our Colorado service area, which does not have
weather-normalized rates.
Partially offsetting these increases was a decrease of
approximately $8.9 million in revenue-related taxes
primarily due to lower revenues, on which the tax is calculated,
in the current-year quarter compared to the prior-year quarter.
This decrease was partially offset by a $0.8 million
quarter-over-quarter decrease in the associated franchise and
state gross receipts tax expense recorded as a component of
taxes other than income, resulting in an $8.1 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, decreased
$0.7 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, decreased $6.9 million, primarily due to
lower legal, fuel and other administrative costs.
Depreciation and amortization expense increased
$4.4 million for the second quarter of fiscal 2009 compared
with second quarter of fiscal 2008. The increase primarily was
attributable to additional assets placed in service during the
current-year period.
Results for the quarter include the aforementioned
$10.5 million tax benefit, which more than offset the
decrease attributable to the absence in the current-year quarter
of a $1.2 million gain on the sale of irrigation assets in
our West Texas Division in the prior-year quarter.
Recent
Ratemaking Developments
Significant ratemaking developments that occurred during the six
months ended March 31, 2009 are discussed below. The
amounts described below represent the operating income that was
requested or received in each rate filing, which may not
necessarily reflect the stated amount referenced in the final
order, as certain operating costs may have changed as a result
of a commissions final ruling.
42
Annual
Rate Filing Mechanisms
In March 2009, the Mid-Tex Division filed its second RRM with
the Settled Cities. The filing requested an increase in
operating income of $9.7 million for the Settled Cities.
Representatives of the Settled Cities are currently reviewing
the filing and a final determination is expected in July 2009.
Beginning in November 2008, rates were implemented from our
first RRM filing with the Settled Cities, which resulted in an
increase in operating income on a system-wide basis of
approximately $27.3 million. The impact to the Mid-Tex
Division for the Settled Cities was approximately
$21.8 million.
In April 2009, the West Texas Division filed its second RRM with
the West Texas Cities. The filing requested an increase in
operating income of $11.1 million. Representatives of the
West Texas Cities are currently reviewing the filing and a final
determination is expected in August 2009. Beginning in November
2008, rates were implemented from our first RRM with the West
Texas Cities, which resulted in an increase in operating income
of $4.5 million, of which $3.9 million is being
collected over a
91/2
month period.
In April 2009, the City of Lubbock approved an RRM tariff
similar to the RRM tariff utilized by the West Texas Cities. The
West Texas Division filed its first RRM with the City of Lubbock
on April 15, 2009. The filing requested an increase in
operating income of $3.5 million. The City of Lubbock is
currently reviewing the filing and a final determination is
expected in October 2009.
In December 2008, the Louisiana Division filed its
TransLa annual rate stabilization clause with the Louisiana
Public Service Commission (LPSC) for the test year ended
September 30, 2008. The filing resulted in an increase in
operating income of $0.6 million and was implemented in
April 2009.
In April 2009, the Louisiana Division filed its LGS annual rate
stabilization clause with the LPSC requesting an increase in
operating income of $3.9 million. The filing was for the
test year ended December 31, 2008. We anticipate final
resolution of this proceeding by June 2009.
In September 2008, we filed our Mississippi stable rate filing
with the Mississippi Public Service Commission (MPSC) requesting
an increase of $3.5 million. In January 2009, we withdrew
this request after we were unable to reach a mutually agreeable
settlement with the MPSC.
GRIP
Filings
In May 2008, the Mid-Tex Division made a GRIP filing seeking a
$10.3 million increase on a system-wide basis. However,
this filing was only applicable to the City of Dallas and the
Mid-Tex environs and sought a $1.8 million increase for
customers in those service areas. Rates were approved for this
filing in December 2008 and were implemented in January 2009.
However, in April 2009, the City of Dallas challenged the
legality of the implementation of the GRIP rates, which the
Company is contesting in the District Courts of Dallas and
Travis Counties.
In March 2009, the Mid-Tex Division made a GRIP filing seeking
an $18.7 million increase on a system-wide basis. However,
this filing is applicable to the City of Dallas only and seeks a
$2.7 million increase for customers in the City of Dallas.
The City of Dallas has until July 10, 2009 to either accept
or object to the filing. If this filing is accepted, the rates
will go into effect until such time that they are superseded by
the statement of intent filed with the City of Dallas discussed
below.
Rate Case
Filings
In October 2008, our Kentucky/Mid-States Division filed a rate
case with the Tennessee Regulatory Authority seeking an increase
in operating income of $6.3 million. In January 2009, the
Consumer Advocate and Protection Division recommended a decrease
in rates of $3.7 million. In March 2009, a unanimous
stipulation was filed and approved in the case. The parties
agreed to an increase in operating income of $2.5 million
with a stated return on equity of 10.3 percent. The
increase in rates was implemented in April 2009.
In November 2008, the Mid-Tex Division filed a statement of
intent to increase operating income for customers within the
City of Dallas by $9.1 million. The City of Dallas
suspended the filing on December 10, 2008 and denied the
increase in March 2009. The Company has appealed the filing and
in April 2009 we requested an increase in operating income of
$7.5 million and concurrently filed for a statement of
intent to increase operating income $1.3 million applicable
to the Mid-Tex unincorporated areas. A final ruling by the
Railroad Commission of Texas (RRC) is expected by October 2009.
If the statement of intent applicable to the
43
City of Dallas is approved by the RRC, the new rates implemented
could supersede the City of Dallas GRIP rates discussed above.
In April 2009, the Kentucky/Mid-States Division filed an
expedited rate case with the Virginia State Corporation
Commission seeking an increase in operating income of
$1.7 million. Interim rates will be implemented subject to
refund on May 1, 2009. The application is currently in
discovery with a final determination expected in October 2009.
Other
Ratemaking Activity
In May 2007, our Mid-Tex Division filed for a
36-month gas
contract review filing. This filing was mandated by prior RRC
orders and related to the prudency of gas purchases made from
November 2003 through October 2006, which total approximately
$2.7 billion. The intervening parties recommended
disallowances ranging from $58 million to $89 million.
A hearing was held at the RRC in September 2008. In December
2008, a proposal for decision was issued by the Hearing Examiner
recommending no gas cost disallowance. In February 2009, the RRC
approved the Hearing Examiners recommendation to disallow
no gas costs.
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
March 31, 2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
27,061
|
|
|
$
|
28,260
|
|
|
$
|
(1,199
|
)
|
Third-party transportation
|
|
|
23,846
|
|
|
|
18,229
|
|
|
|
5,617
|
|
Storage and park and lend services
|
|
|
2,657
|
|
|
|
1,862
|
|
|
|
795
|
|
Other
|
|
|
5,670
|
|
|
|
3,089
|
|
|
|
2,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
59,234
|
|
|
|
51,440
|
|
|
|
7,794
|
|
Operating expenses
|
|
|
24,905
|
|
|
|
21,378
|
|
|
|
3,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
34,329
|
|
|
|
30,062
|
|
|
|
4,267
|
|
Miscellaneous income
|
|
|
283
|
|
|
|
209
|
|
|
|
74
|
|
Interest charges
|
|
|
7,349
|
|
|
|
6,776
|
|
|
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
27,263
|
|
|
|
23,495
|
|
|
|
3,768
|
|
Income tax expense
|
|
|
7,798
|
|
|
|
8,271
|
|
|
|
(473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,465
|
|
|
$
|
15,224
|
|
|
$
|
4,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
193,356
|
|
|
|
223,476
|
|
|
|
(30,120
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
123,285
|
|
|
|
141,108
|
|
|
|
(17,823
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
The $7.8 million increase in gross profit was attributable
primarily to a $3.6 million increase resulting from higher
transportation fees on through-system deliveries due to market
conditions and a $3.3 million increase from higher
demand-based fees. The improvement in gross profit also reflects
a $2.9 million gain on the routine sale of excess gas
during the quarter and a $1.4 million increase due to our
2006 and 2007 GRIP filings. These increases were partially
offset by a $4.1 million decrease arising from lower
city-gate, electrical generation, Barnett Shale and HUB
deliveries.
Operating expenses increased $3.5 million primarily due to
increased employee and pipeline maintenance costs.
Results for the quarter also include the aforementioned
$1.7 million tax benefit associated with updating the rates
used to determine our deferred taxes.
Recent
Ratemaking Developments
In February 2009, the Atmos Pipeline Texas Division
made a GRIP filing seeking an increase in operating income of
$6.3 million. The filing was approved by the RRC and a
final order was issued in April 2009.
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 economically hedge the original financial
instruments. If AEM elects to defer the withdrawal of gas, it
will reset its financial instruments by settling the original
financial instruments and executing new financial instruments to
correspond to the revised withdrawal schedule.
We use financial instruments, designated as fair value hedges,
to hedge our natural gas inventory used in our natural gas
marketing storage activities. These financial instruments are
marked to market each month based upon the NYMEX price with
changes in fair value recognized as unrealized gains and losses
in the period of change. The hedged natural gas inventory is
marked to market at the end of each month based on
45
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.
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the three months ended March 31, 2009
and 2008 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
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
23,165
|
|
|
$
|
26,195
|
|
|
$
|
(3,030
|
)
|
Asset optimization
|
|
|
(2,073
|
)
|
|
|
27,737
|
|
|
|
(29,810
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,092
|
|
|
|
53,932
|
|
|
|
(32,840
|
)
|
Unrealized margins
|
|
|
2,452
|
|
|
|
(37,600
|
)
|
|
|
40,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
23,544
|
|
|
|
16,332
|
|
|
|
7,212
|
|
Operating expenses
|
|
|
13,165
|
|
|
|
6,306
|
|
|
|
6,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
10,379
|
|
|
|
10,026
|
|
|
|
353
|
|
Miscellaneous income
|
|
|
118
|
|
|
|
602
|
|
|
|
(484
|
)
|
Interest charges
|
|
|
3,461
|
|
|
|
2,002
|
|
|
|
1,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
7,036
|
|
|
|
8,626
|
|
|
|
(1,590
|
)
|
Income tax expense
|
|
|
3,688
|
|
|
|
3,347
|
|
|
|
341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
3,348
|
|
|
$
|
5,279
|
|
|
$
|
(1,931
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
123,066
|
|
|
|
136,677
|
|
|
|
(13,611
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
104,973
|
|
|
|
120,023
|
|
|
|
(15,050
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
21.9
|
|
|
|
20.7
|
|
|
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $7.2 million increase in our natural gas marketing
segments gross profit was driven primarily by a
$40.1 million increase in unrealized margins. This increase
reflects lower volatility during the current quarter
46
compared with the prior-year quarter between current cash prices
used to value our physical inventory and future natural gas
prices, which influence the prices used to value the financial
instruments used to hedge our physical inventory.
The increase in unrealized margins was partially offset by a
$29.8 million decrease in asset optimization margins.
During the current quarter, as a result of falling current cash
prices, AEM elected to defer storage withdrawals, reset the
corresponding financial instruments and inject additional gas
into storage to increase the potential gross profit it could
realize in future periods from its asset optimization
activities. Accordingly, AEMs results for the quarter
reflect lower realized gains from storage withdrawals and the
settlement of the associated financial instruments. In the
prior-year quarter, AEM elected to withdraw storage and realize
the corresponding storage withdrawal gains.
In addition, delivered gas margins decreased $3.0 million
compared with the prior-year quarter largely attributable to a
10 percent decrease in gross sales volumes, primarily
associated with lower industrial demand due to the current
economic climate.
Per-unit
margins for the quarter were approximately two percent lower
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 taxes,
increased $6.9 million primarily due to an increase in
legal 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 March 31, 2009,
December 31, 2008 and September 30, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated Net
|
|
|
|
|
|
|
Net Physical
|
|
|
Economic
|
|
|
Unrealized
|
|
|
Potential Gross
|
|
Period Ending
|
|
Position
|
|
|
Gross Profit
|
|
|
Gain
|
|
|
Profit(1)
|
|
|
|
(Bcf)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
March 31, 2009
|
|
|
21.9
|
|
|
$
|
33.4
|
|
|
$
|
2.4
|
|
|
$
|
31.0
|
|
December 31, 2008
|
|
|
16.3
|
|
|
$
|
20.7
|
|
|
$
|
4.8
|
|
|
$
|
15.9
|
|
September 30, 2008
|
|
|
8.0
|
|
|
$
|
48.5
|
|
|
$
|
36.4
|
|
|
$
|
12.1
|
|
|
|
|
(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 our
investors a more comprehensive view of our asset optimization
efforts and thus a better understanding of these activities than
would be presented by GAAP measures alone. |
As of March 31, 2009, based upon AEMs planned
inventory withdrawal schedule and associated planned settlement
of financial instruments, the economic gross profit was
$33.4 million. This amount will be reduced by
$2.4 million of net unrealized gains recorded in the
financial statements as of March 31, 2009 that will reverse
when the inventory is withdrawn and the accompanying financial
instruments are settled. Therefore, the potential gross profit
was $31.0 million at March 31, 2009.
During the six months ended March 31, 2009, AEM increased
its potential gross profit by $18.9 million to
$31.0 million. In the first quarter, AEM withdrew gas and
substantially realized the associated potential gross profit
reported as of September 30, 2008. Since that time, as a
result of falling current cash prices, AEM
47
has been deferring storage withdrawals and has been a net
injector of gas into storage to increase the potential gross
profit it could realize in future periods from its asset
optimization activities. As a result of these activities, AEM
has increased its net physical position by 13.9 Bcf since
September 30, 2008. However, the captured spreads on these
positions have been lower than those captured as of
September 30, 2008, resulting in a lower economic gross
profit compared to that time, but higher than the economic gross
profit of $10.8 million as of March 31, 2008. This
decrease from September 2008 to March 2009 was partially offset
by lower unrealized gains associated with these positions
primarily due to lower current cash prices.
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
March 31, 2009 will be fully realized in the future nor can
we predict in what time periods such realization may occur.
Further, if we experience operational or other issues which
limit our ability to optimally manage our stored gas positions,
our earnings could be adversely impacted. Assuming AEM fully
executes its plan in place on March 31, 2009, without
encountering operational or other issues, we anticipate that
approximately $1 million of the potential gross profit as
of March 31, 2009 will be recognized in fiscal 2009 with
the remaining $30 million expected to be recognized during
the first six months of fiscal 2010.
Pipeline,
Storage and Other Segment
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS
owns and operates a 21 mile pipeline located in New
Orleans, Louisiana. This pipeline is primarily used to aggregate
gas supply for our regulated natural gas distribution division
in Louisiana and for AEM, but also provides limited third party
transportation services.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are asset management plans with regulated
affiliates of the Company which have been approved by applicable
state regulatory commissions. Generally, these asset management
plans require APS to share with our regulated customers a
portion of the profits earned from these arrangements.
Further, APS owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
pipeline capacity to meet customer demand during peak periods.
Finally, APS manages our natural gas gathering operations, which
were limited in nature as of March 31, 2009.
Results for this segment are impacted primarily 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.
48
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the three months ended March 31, 2009
and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Asset optimization
|
|
$
|
15,157
|
|
|
$
|
6,604
|
|
|
$
|
8,553
|
|
Storage and transportation services
|
|
|
3,312
|
|
|
|
3,895
|
|
|
|
(583
|
)
|
Other
|
|
|
350
|
|
|
|
1,113
|
|
|
|
(763
|
)
|
Unrealized margins
|
|
|
(8,203
|
)
|
|
|
(1,928
|
)
|
|
|
(6,275
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
10,616
|
|
|
|
9,684
|
|
|
|
932
|
|
Operating expenses
|
|
|
2,591
|
|
|
|
2,227
|
|
|
|
364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
8,025
|
|
|
|
7,457
|
|
|
|
568
|
|
Miscellaneous income
|
|
|
2,060
|
|
|
|
1,942
|
|
|
|
118
|
|
Interest charges
|
|
|
677
|
|
|
|
524
|
|
|
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
9,408
|
|
|
|
8,875
|
|
|
|
533
|
|
Income tax expense
|
|
|
4,794
|
|
|
|
3,500
|
|
|
|
1,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4,614
|
|
|
$
|
5,375
|
|
|
$
|
(761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit from our pipeline, storage and other segment
increased $0.9 million primarily due to an
$8.6 million increase in asset optimization margins
resulting from larger realized gains from the settlement of
financial positions associated with storage and trading
activities and basis gains earned from utilizing controlled
pipeline capacity. These increases were partially offset by a
$6.3 million decrease in unrealized margins associated with
our asset optimization activities due to a widening of the
spreads between current cash prices and forward natural gas
prices.
Operating expenses for the three months ended March 31,
2009 were consistent with the prior-year quarter.
49
Six
Months Ended March 31, 2009 compared with Six Months Ended
March 31, 2008
Natural
Gas Distribution Segment
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the six months ended March 31,
2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
665,464
|
|
|
$
|
630,724
|
|
|
$
|
34,740
|
|
Operating expenses
|
|
|
379,231
|
|
|
|
369,709
|
|
|
|
9,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
286,233
|
|
|
|
261,015
|
|
|
|
25,218
|
|
Miscellaneous income
|
|
|
3,956
|
|
|
|
4,146
|
|
|
|
(190
|
)
|
Interest charges
|
|
|
61,708
|
|
|
|
60,298
|
|
|
|
1,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
228,481
|
|
|
|
204,863
|
|
|
|
23,618
|
|
Income tax expense
|
|
|
76,772
|
|
|
|
79,043
|
|
|
|
(2,271
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
151,709
|
|
|
$
|
125,820
|
|
|
$
|
25,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
213,006
|
|
|
|
220,335
|
|
|
|
(7,329
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
69,397
|
|
|
|
73,479
|
|
|
|
(4,082
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
282,403
|
|
|
|
293,814
|
|
|
|
(11,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.44
|
|
|
$
|
0.02
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
7.61
|
|
|
$
|
8.26
|
|
|
$
|
(0.65
|
)
|
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the six months ended March 31, 2009 and 2008. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
March 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
133,052
|
|
|
$
|
122,704
|
|
|
$
|
10,348
|
|
Kentucky/Mid-States
|
|
|
46,429
|
|
|
|
44,043
|
|
|
|
2,386
|
|
Louisiana
|
|
|
34,366
|
|
|
|
31,168
|
|
|
|
3,198
|
|
West Texas
|
|
|
22,819
|
|
|
|
13,895
|
|
|
|
8,924
|
|
Mississippi
|
|
|
25,206
|
|
|
|
24,343
|
|
|
|
863
|
|
Colorado-Kansas
|
|
|
22,224
|
|
|
|
22,224
|
|
|
|
|
|
Other
|
|
|
2,137
|
|
|
|
2,638
|
|
|
|
(501
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
286,233
|
|
|
$
|
261,015
|
|
|
$
|
25,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $34.7 million increase in natural gas distribution
gross profit primarily reflects a net $37.2 million
increase in rates. The net increase in rates was attributable
primarily to the Mid-Tex Division, which increased
$27.8 million as a result of the implementation of its 2008
Rate Review Mechanism (RRM) filing with all
50
incorporated cities in the division other than the City of
Dallas (the Settled Cities) and rate adjustments for customers
in the City of Dallas. The current year period also reflects a
$9.4 million increase in rate adjustments primarily in
Georgia, Kansas, Louisiana and West Texas. The increase in gross
profit also reflects the reversal of a $7.0 million
uncollectible gas cost accrual recorded in a prior year and an
$8.3 million increase attributable to a non-recurring
update to our estimate for gas delivered to customers but not
yet billed to reflect changes in base rates in several of our
jurisdictions recorded in the fiscal first quarter. These
increases in gross profit were partially offset by a
$14.8 million decrease as a result of a four percent
decrease in distribution throughput primarily associated with
lower residential and commercial consumption and warmer weather
in our Colorado service area, which does not have
weather-normalized rates.
Partially offsetting these increases was a decrease of
approximately $9.2 million in revenue-related taxes
primarily due to lower revenues, on which the tax is calculated,
in the current-year period compared to the prior-year period.
This decrease, combined with a $7.3 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 $16.5 million
decrease 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
$9.5 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, decreased $4.7 million, primarily due to
lower legal, fuel and other administrative costs. These
decreases were partially offset by a $2.1 million noncash
charge in the first quarter of fiscal 2009 to impair certain
available-for-sale investments due to the recent deterioration
of the financial markets.
Depreciation and amortization expense increased
$8.7 million for the current-year period compared with six
months ended March 31, 2008. The increase primarily was
attributable to additional assets placed in service during the
current-year period.
Results for the prior-year period also included a
$1.2 million gain on the sale of irrigation assets in our
West Texas Division.
Interest charges allocated to the natural gas distribution
segment increased $1.4 million due to higher average
short-term debt balances, interest rates and commitment fees
experienced during the current-year period compared to the
prior-year period. These increases are associated with the
recent adverse conditions in the credit markets.
Results for the current-year period include the aforementioned
$10.5 million tax benefit associated with updating the
rates used to determine our deferred taxes.
51