e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
June 30, 2006
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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
|
Commission File Number 1-10042
Atmos Energy
Corporation
(Exact name of registrant as
specified in its charter)
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|
|
Texas and Virginia
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|
75-1743247
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(State or other jurisdiction
of
incorporation or organization)
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|
(IRS employer
identification no.)
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Three Lincoln Centre,
Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal
executive offices)
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75240
(Zip code)
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(972) 934-9227
(Registrants
telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of Accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
Number of shares outstanding of each of the issuers
classes of common stock, as of July 31, 2006.
|
|
|
Class
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Shares Outstanding
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|
No Par Value
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81,595,723
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TABLE OF CONTENTS
GLOSSARY
OF KEY TERMS
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|
|
AEH
|
|
Atmos Energy Holdings, Inc.
|
AEM
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|
Atmos Energy Marketing, LLC
|
AES
|
|
Atmos Energy Services, LLC
|
APB
|
|
Accounting Principles Board
|
APS
|
|
Atmos Pipeline and Storage, LLC
|
Bcf
|
|
Billion cubic feet
|
EITF
|
|
Emerging Issues Task Force
|
FASB
|
|
Financial Accounting Standards
Board
|
FERC
|
|
Federal Energy Regulatory
Commission
|
FIN
|
|
FASB Interpretation
|
Fitch
|
|
Fitch Ratings, Ltd.
|
GPSC
|
|
Georgia Public Service Commission
|
GRIP
|
|
Gas Reliability Infrastructure
Program
|
KPSC
|
|
Kentucky Public Service Commission
|
LGS
|
|
Louisiana Gas Service Company and
LGS Natural Gas Company, which were acquired July 1, 2001
|
LPSC
|
|
Louisiana Public Service Commission
|
Mcf
|
|
Thousand cubic feet
|
MMcf
|
|
Million cubic feet
|
Moodys
|
|
Moodys Investors Services,
Inc.
|
MPSC
|
|
Mississippi Public Service
Commission
|
NYMEX
|
|
New York Mercantile Exchange, Inc.
|
RRC
|
|
Railroad Commission of Texas
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RSC
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Rate Stabilization Clause
|
S&P
|
|
Standard & Poors
Corporation
|
SEC
|
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United States Securities and
Exchange Commission
|
SFAS
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Statement of Financial Accounting
Standards
|
TLGP
|
|
Trans Louisiana Gas Pipeline
|
TRA
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|
Tennessee Regulatory Authority
|
TXU Gas
|
|
TXU Gas Company, which was
acquired on October 1, 2004
|
WNA
|
|
Weather Normalization Adjustment
|
1
PART I.
FINANCIAL INFORMATION
|
|
Item 1.
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Financial
Statements
|
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(In thousands, except
|
|
|
|
share data)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
4,993,093
|
|
|
$
|
4,765,610
|
|
Less accumulated depreciation and
amortization
|
|
|
1,414,010
|
|
|
|
1,391,243
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
3,579,083
|
|
|
|
3,374,367
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
26,849
|
|
|
|
40,116
|
|
Cash held on deposit in margin
account
|
|
|
58,176
|
|
|
|
80,956
|
|
Accounts receivable, net
|
|
|
409,087
|
|
|
|
454,313
|
|
Gas stored underground
|
|
|
437,069
|
|
|
|
450,807
|
|
Other current assets
|
|
|
118,990
|
|
|
|
238,238
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,050,171
|
|
|
|
1,264,430
|
|
Goodwill and intangible assets
|
|
|
737,349
|
|
|
|
737,787
|
|
Deferred charges and other assets
|
|
|
249,874
|
|
|
|
276,943
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,616,477
|
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND
LIABILITIES
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
|
|
|
|
|
|
Common stock, no par value (stated
at $.005 per share); 200,000,000 shares authorized;
issued and outstanding:
|
|
|
|
|
|
|
|
|
June 30, 2006
81,538,149 shares;
September 30, 2005 80,539,401 shares
|
|
$
|
408
|
|
|
$
|
403
|
|
Additional paid-in capital
|
|
|
1,456,032
|
|
|
|
1,426,523
|
|
Retained earnings
|
|
|
243,956
|
|
|
|
178,837
|
|
Accumulated other comprehensive loss
|
|
|
(35,840
|
)
|
|
|
(3,341
|
)
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
1,664,556
|
|
|
|
1,602,422
|
|
Long-term debt
|
|
|
2,180,752
|
|
|
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,845,308
|
|
|
|
3,785,526
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued
liabilities
|
|
|
306,805
|
|
|
|
461,314
|
|
Other current liabilities
|
|
|
407,575
|
|
|
|
503,368
|
|
Short-term debt
|
|
|
297,087
|
|
|
|
144,809
|
|
Current maturities of long-term debt
|
|
|
3,331
|
|
|
|
3,264
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,014,798
|
|
|
|
1,112,755
|
|
Deferred income taxes
|
|
|
283,757
|
|
|
|
292,207
|
|
Regulatory cost of removal
obligation
|
|
|
275,955
|
|
|
|
263,424
|
|
Deferred credits and other
liabilities
|
|
|
196,659
|
|
|
|
199,615
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,616,477
|
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
2
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Utility segment
|
|
$
|
402,044
|
|
|
$
|
501,735
|
|
Natural gas marketing segment
|
|
|
562,447
|
|
|
|
466,835
|
|
Pipeline and storage segment
|
|
|
35,862
|
|
|
|
33,449
|
|
Other nonutility segment
|
|
|
1,413
|
|
|
|
1,421
|
|
Intersegment eliminations
|
|
|
(138,523
|
)
|
|
|
(96,563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
863,243
|
|
|
|
906,877
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
232,192
|
|
|
|
326,502
|
|
Natural gas marketing segment
|
|
|
563,333
|
|
|
|
456,440
|
|
Pipeline and storage segment
|
|
|
379
|
|
|
|
(1,733
|
)
|
Other nonutility segment
|
|
|
|
|
|
|
|
|
Intersegment eliminations
|
|
|
(137,161
|
)
|
|
|
(95,606
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
658,743
|
|
|
|
685,603
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
204,500
|
|
|
|
221,274
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
104,380
|
|
|
|
91,443
|
|
Depreciation and amortization
|
|
|
46,838
|
|
|
|
43,448
|
|
Taxes, other than income
|
|
|
48,479
|
|
|
|
46,915
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
199,697
|
|
|
|
181,806
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
4,803
|
|
|
|
39,468
|
|
Miscellaneous income
|
|
|
963
|
|
|
|
1,524
|
|
Interest charges
|
|
|
35,944
|
|
|
|
33,689
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(30,178
|
)
|
|
|
7,303
|
|
Income tax expense (benefit)
|
|
|
(12,033
|
)
|
|
|
2,817
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(18,145
|
)
|
|
$
|
4,486
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share
|
|
$
|
(0.22
|
)
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
Diluted net income (loss) per share
|
|
$
|
(0.22
|
)
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.315
|
|
|
$
|
0.310
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
80,840
|
|
|
|
79,683
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
80,840
|
|
|
|
80,144
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Utility segment
|
|
$
|
3,254,674
|
|
|
$
|
2,650,793
|
|
Natural gas marketing segment
|
|
|
2,482,921
|
|
|
|
1,473,527
|
|
Pipeline and storage segment
|
|
|
121,057
|
|
|
|
122,685
|
|
Other nonutility segment
|
|
|
4,500
|
|
|
|
4,058
|
|
Intersegment eliminations
|
|
|
(682,243
|
)
|
|
|
(290,477
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
5,180,909
|
|
|
|
3,960,586
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
2,488,906
|
|
|
|
1,895,181
|
|
Natural gas marketing segment
|
|
|
2,413,511
|
|
|
|
1,425,128
|
|
Pipeline and storage segment
|
|
|
590
|
|
|
|
8,895
|
|
Other nonutility segment
|
|
|
|
|
|
|
|
|
Intersegment eliminations
|
|
|
(678,591
|
)
|
|
|
(287,889
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
4,224,416
|
|
|
|
3,041,315
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
956,493
|
|
|
|
919,271
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
325,295
|
|
|
|
305,640
|
|
Depreciation and amortization
|
|
|
137,174
|
|
|
|
132,771
|
|
Taxes, other than income
|
|
|
158,691
|
|
|
|
140,537
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
621,160
|
|
|
|
578,948
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
335,333
|
|
|
|
340,323
|
|
Miscellaneous income (expense)
|
|
|
(1,028
|
)
|
|
|
2,867
|
|
Interest charges
|
|
|
107,625
|
|
|
|
99,304
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
226,680
|
|
|
|
243,886
|
|
Income tax expense
|
|
|
85,002
|
|
|
|
91,299
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
141,678
|
|
|
$
|
152,587
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
1.76
|
|
|
$
|
1.96
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
1.75
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.945
|
|
|
$
|
0.930
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
80,520
|
|
|
|
78,009
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
81,013
|
|
|
|
78,478
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating
Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
141,678
|
|
|
$
|
152,587
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
Charged to depreciation and
amortization
|
|
|
137,174
|
|
|
|
132,771
|
|
Charged to other accounts
|
|
|
359
|
|
|
|
634
|
|
Deferred income taxes
|
|
|
36,160
|
|
|
|
17,703
|
|
Other
|
|
|
12,063
|
|
|
|
7,593
|
|
Net assets / liabilities from risk
management activities
|
|
|
(3,940
|
)
|
|
|
14,276
|
|
Net change in operating assets and
liabilities
|
|
|
(100,051
|
)
|
|
|
61,846
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
223,443
|
|
|
|
387,410
|
|
Cash Flows From Investing
Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(322,691
|
)
|
|
|
(226,851
|
)
|
Acquisitions
|
|
|
|
|
|
|
(1,916,654
|
)
|
Other, net
|
|
|
(4,811
|
)
|
|
|
(1,648
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(327,502
|
)
|
|
|
(2,145,153
|
)
|
Cash Flows From Financing
Activities
|
|
|
|
|
|
|
|
|
Net increase in short-term debt
|
|
|
152,278
|
|
|
|
|
|
Net proceeds from issuance of
long-term debt
|
|
|
|
|
|
|
1,385,847
|
|
Repayment of long-term debt
|
|
|
(2,618
|
)
|
|
|
(102,801
|
)
|
Settlement of Treasury lock
agreements
|
|
|
|
|
|
|
(43,770
|
)
|
Cash dividends paid
|
|
|
(76,559
|
)
|
|
|
(74,048
|
)
|
Issuance of common stock
|
|
|
17,691
|
|
|
|
32,206
|
|
Net proceeds from equity offering
|
|
|
|
|
|
|
382,014
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
90,792
|
|
|
|
1,579,448
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash
equivalents
|
|
|
(13,267
|
)
|
|
|
(178,295
|
)
|
Cash and cash equivalents at
beginning of period
|
|
|
40,116
|
|
|
|
201,932
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of period
|
|
$
|
26,849
|
|
|
$
|
23,637
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
5
ATMOS
ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2006
Atmos Energy Corporation (Atmos or the
Company) and its subsidiaries are engaged primarily in the
natural gas utility business as well as other natural gas
nonutility businesses. Our natural gas utility business
distributes natural gas through sales and transportation
arrangements to approximately 3.2 million residential,
commercial, public authority and industrial customers throughout
our seven regulated natural gas utility divisions, in the
service areas described below:
|
|
|
Division
|
|
Service Area
|
|
Atmos Energy Colorado-Kansas
Division
|
|
Colorado, Kansas,
Missouri(1)
|
Atmos Energy Kentucky Division
|
|
Kentucky
|
Atmos Energy Louisiana Division
|
|
Louisiana
|
Atmos Energy Mid-States Division
|
|
Georgia(1),
Illinois(1),
Iowa(1),
Missouri(1),
Tennessee,
Virginia(1)
|
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 locations where we have more limited service areas. |
Our nonutility businesses operate in 22 states and include
our natural gas marketing operations, pipeline and storage
operations and other nonutility operations. These operations are
either organized under or managed by Atmos Energy Holdings, Inc.
(AEH), which is wholly-owned by the Company.
Our natural gas marketing operations are managed by Atmos Energy
Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides
a variety of natural gas management services to municipalities,
natural gas utility systems and industrial natural gas
customers, primarily in the southeastern and midwestern states
and to our Kentucky, Louisiana and Mid-States utility divisions.
These services consist primarily of furnishing natural gas
supplies at fixed and market-based prices, contract negotiation
and administration, load forecasting, gas storage acquisition
and management services, transportation services, peaking sales
and balancing services, capacity utilization strategies and gas
price hedging through the use of derivative instruments.
Our pipeline and storage business includes the regulated
operations of our Atmos Pipeline Texas Division, a
division of Atmos Energy Corporation, and the nonregulated
operations of Atmos Pipeline and Storage, LLC (APS), which is
wholly-owned by AEH. The Atmos Pipeline Texas
Division transports natural gas to our Atmos Energy Mid-Tex
Division and to third parties, as well as manages five
underground storage reservoirs in Texas. Through APS, we own or
have an interest in underground storage fields in Kentucky and
Louisiana. We also use these storage facilities to reduce the
need to contract for additional pipeline capacity to meet
customer demand during peak periods.
Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services, LLC (AES) and Atmos Power
Systems, Inc., which are each wholly-owned by AEH. Through AES,
we provide natural gas management services to our utility
operations, other than the Mid-Tex Division. These services
include aggregating and purchasing gas supply, arranging
transportation and storage logistics and ultimately delivering
the gas to our utility service areas at competitive prices in
exchange for revenues that are equal to the costs incurred to
provide these services. Through Atmos Power Systems, Inc., we
have constructed electric peaking power-generating plants and
associated facilities and have entered into agreements to lease
these plants.
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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 and notes 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 in its Annual
Report on
Form 10-K
for the fiscal year ended September 30, 2005. Because of
seasonal and other factors, the results of operations for the
three and nine-month periods ended June 30, 2006 are not
indicative of expected results of operations for the full 2006
fiscal year, which ends September 30, 2006.
Basis
of comparison
Certain prior-period amounts have been reclassified to conform
with the current years presentation.
Significant
accounting policies
Our accounting policies are described in Note 2 to our
Annual Report on
Form 10-K
for the year ended September 30, 2005. Except for the
Companys adoption of Statement of Financial Accounting
Standards (SFAS) 123 (revised), Share-Based Payment,
discussed below, there were no significant changes to our
accounting policies during the nine months ended June 30,
2006.
Additionally, during the second quarter of fiscal 2006, we
completed our annual goodwill impairment assessment. Based on
the assessment performed, our goodwill was not considered to be
impaired.
Stock-based
compensation plans
Our 1998 Long-Term Incentive Plan provides for the granting of
incentive stock options, non-qualified stock options, stock
appreciation rights, bonus stock, time-lapse restricted stock,
performance-based restricted stock units and stock units to
officers, division presidents and other key employees.
Non-employee directors are also eligible to receive stock-based
compensation under the 1998 Long-Term Incentive Plan. The
objectives of this plan include attracting and retaining the
best personnel, providing for additional performance incentives
and promoting our success by providing employees with the
opportunity to acquire our common stock.
On October 1, 2005, the Company adopted SFAS 123
(revised), Share-Based Payment (SFAS 123(R)). This
standard revises SFAS 123, Accounting for Stock-Based
Compensation and supersedes Accounting Principles Board
(APB) Opinion 25, Accounting for Stock Issued to
Employees. Under SFAS 123(R), the Company is required
to measure the cost of employee services received in exchange
for stock options and similar awards based on the grant-date
fair value of the award and recognize this cost in the income
statement over the period during which an employee is required
to provide service in exchange for the award.
We adopted SFAS 123(R) using the modified prospective
method. Under this transition method, stock-based compensation
expense for the three and nine months ended June 30, 2006
included: (i) compensation expense for all stock-based
compensation awards granted prior to, but not yet vested as of
October 1, 2005, based on the grant-date fair value
estimated in accordance with the original provisions of
SFAS 123; and (ii) compensation expense for all
stock-based compensation awards granted subsequent to
October 1, 2005, based on the grant-date fair value
estimated in accordance with the provisions of SFAS 123(R).
We recognize compensation expense on a straight-line basis over
the requisite service period of the award. The impact of
adoption on total stock-based compensation expense included in
our statement of income for the three and nine months ended
June 30, 2006 was less than $0.1 million and
$0.4 million and was recorded as a component of operation
and maintenance expense. In accordance with the modified
prospective method, financial results for prior periods have not
been restated.
Prior to October 1, 2005, we accounted for these plans
under the intrinsic-value method described in APB
Opinion 25, as permitted by SFAS 123. Under this
method, no compensation cost for stock options was recognized
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
for stock-option awards granted at or above fair-market value.
Awards of restricted stock were valued at the market price of
the Companys common stock on the date of grant. The
unearned compensation was amortized as a component of operation
and maintenance expense over the vesting period of the
restricted stock.
Total stock-based compensation expense for the three and nine
months ended June 30, 2006 was $2.1 million and
$4.3 million as compared to $0.9 million and
$2.4 million for the three and nine months ended
June 30, 2005. Had compensation expense for our stock-based
awards been recognized as prescribed by SFAS 123, our net
income and earnings per share for the three and nine months
ended June 30, 2005 would have been impacted as shown in
the following table:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30, 2005
|
|
|
June 30, 2005
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income as reported
|
|
$
|
4,486
|
|
|
$
|
152,587
|
|
Restricted stock compensation
expense included in income, net of tax
|
|
|
542
|
|
|
|
1,514
|
|
Total stock-based employee
compensation expense determined under
fair-value-based
method for all awards, net of taxes
|
|
|
(676
|
)
|
|
|
(2,114
|
)
|
|
|
|
|
|
|
|
|
|
Net income pro forma
|
|
$
|
4,352
|
|
|
$
|
151,987
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
Basic earnings per
share as reported
|
|
$
|
0.06
|
|
|
$
|
1.96
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per
share pro forma
|
|
$
|
0.05
|
|
|
$
|
1.95
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per
share as reported
|
|
$
|
0.06
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per
share pro forma
|
|
$
|
0.05
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
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 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 separately reported.
8
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Significant regulatory assets and liabilities as of
June 30, 2006 and September 30, 2005 included the
following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Merger and integration costs, net
|
|
$
|
8,895
|
|
|
$
|
9,150
|
|
Deferred gas cost
|
|
|
24,645
|
|
|
|
38,173
|
|
Environmental costs
|
|
|
1,234
|
|
|
|
1,357
|
|
Rate case costs
|
|
|
8,986
|
|
|
|
11,314
|
|
Deferred franchise fees
|
|
|
1,202
|
|
|
|
6,710
|
|
Other
|
|
|
8,921
|
|
|
|
9,313
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
53,883
|
|
|
$
|
76,017
|
|
|
|
|
|
|
|
|
|
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
69,542
|
|
|
$
|
134,048
|
|
Regulatory cost of removal
obligation
|
|
|
290,604
|
|
|
|
274,989
|
|
Deferred income taxes, net
|
|
|
3,185
|
|
|
|
3,185
|
|
Other
|
|
|
6,570
|
|
|
|
8,084
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
369,901
|
|
|
$
|
420,306
|
|
|
|
|
|
|
|
|
|
|
Currently authorized rates do not include a return on certain of
our merger and integration costs; however, we recover the
amortization of these costs. Merger and integration costs, net,
are generally amortized on a straight-line basis over estimated
useful lives ranging up to 20 years. Environmental costs
have been deferred to be included in future rate filings in
accordance with rulings received from 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, net of related tax, for the three and nine-month periods
ended June 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
(18,145
|
)
|
|
$
|
4,486
|
|
|
$
|
141,678
|
|
|
$
|
152,587
|
|
Unrealized holding gains (losses)
on investments, net of tax expense (benefit) of $(187) and $(7)
for the three months ended June 30, 2006 and 2005 and of
$355 and $722 for the nine months ended June 30, 2006 and
2005
|
|
|
(304
|
)
|
|
|
(11
|
)
|
|
|
580
|
|
|
|
1,178
|
|
Amortization and unrealized losses
on interest rate hedging transactions, net of tax expense
(benefit) of $528 and $528 for the three months ended
June 30, 2006 and 2005 and $1,583 and $(2,190) for the nine
months ended June 30, 2006 and 2005
|
|
|
860
|
|
|
|
860
|
|
|
|
2,581
|
|
|
|
(3,575
|
)
|
Net unrealized losses on commodity
hedging transactions, net of tax benefit of $4,182 and $2,675
for the three months ended June 30, 2006 and 2005 and
$21,858 and $2,672 for the nine months ended June 30, 2006
and 2005
|
|
|
(6,821
|
)
|
|
|
(4,366
|
)
|
|
|
(35,660
|
)
|
|
|
(4,361
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(24,410
|
)
|
|
$
|
969
|
|
|
$
|
109,179
|
|
|
$
|
145,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss, net of tax, as of
June 30, 2006 and September 30, 2005 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive
loss:
|
|
|
|
|
|
|
|
|
Unrealized holding gains on
investments
|
|
$
|
1,264
|
|
|
$
|
684
|
|
Treasury lock agreements
|
|
|
(21,401
|
)
|
|
|
(23,982
|
)
|
Cash flow hedges
|
|
|
(15,703
|
)
|
|
|
19,957
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(35,840
|
)
|
|
$
|
(3,341
|
)
|
|
|
|
|
|
|
|
|
|
Recent
accounting pronouncements
In March 2005, the Financial Accounting Standards Board (FASB)
issued Interpretation No. 47, Accounting for Conditional
Asset Retirement Obligations (FIN 47), which clarifies
that an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation when the
obligation is incurred generally upon acquisition,
construction or development
and/or
through the normal operation of the asset, if the fair value of
the liability can be reasonably estimated. A conditional asset
retirement obligation is a legal obligation to perform an asset
retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. Uncertainty
about the timing
and/or
method of settlement is required to be factored into the
measurement of the liability when sufficient information exists.
FIN 47 also clarifies when an entity would have sufficient
information to reasonably estimate the fair value of an asset
retirement
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
obligation. We will be required to apply the provisions of
FIN 47 by September 30, 2006. We are currently
evaluating the impact that FIN 47 may have on our financial
position, results of operations and cash flows.
In February 2006, the FASB issued SFAS 155, Accounting
for Certain Hybrid Financial Instruments, which amends
SFAS 133, Accounting for Derivative Instruments and
Hedging Activities and SFAS 140, Accounting for
Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities. SFAS 155 (a) permits fair value
remeasurement for any hybrid financial instrument that contains
an embedded derivative that otherwise would require bifurcation,
(b) clarifies which interest-only strips and principal-only
strips are not subject to the requirements of SFAS 133,
(c) establishes a requirement to evaluate interests in
securitized financial assets to identify interests that are
freestanding derivatives or that are hybrid financial
instruments that contain an embedded derivative requiring
bifurcation, (d) clarifies that concentrations of credit
risk in the form of subordination are not embedded derivatives
and (e) amends SFAS 140 to eliminate the prohibition
on a qualifying special-purpose entity from holding a derivative
financial instrument that pertains to a beneficial interest
other than another derivative financial instrument.
SFAS 155 is effective for all financial instruments
acquired or issued by us after October 1, 2006 but is not
expected to have a material impact on our financial position,
results of operations and cash flows.
In March 2006, the FASB issued SFAS 156, Accounting for
Servicing Financial Assets, which amends SFAS 140,
Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities. SFAS 156
(a) revises guidance on when a servicing asset and
servicing liability should be recognized, (b) requires all
separately recognized servicing assets and servicing liabilities
to be initially measured at fair value, if practicable,
(c) permits an entity to choose to measure servicing assets
and servicing liabilities under the amortization method or fair
value measurement method, (d) at initial adoption, permits
a one-time reclassification of
available-for-sale
securities to trading securities by entities with recognized
servicing rights, without calling into question the treatment of
other
available-for-sale
securities under SFAS 115, provided that the
available-for-sale
securities are identified as offsetting the exposure to changes
in the fair value of servicing assets or liabilities that the
servicer elects to subsequently measure at fair value and
(e) requires separate presentation of servicing assets and
servicing liabilities subsequently measured at fair value in the
statement of financial position and additional footnote
disclosure. We will be required to apply the provisions of
SFAS 156 beginning October 1, 2006 but such
application is not expected to have a material impact on our
financial position, results of operations and cash flows.
In March 2006, the FASB issued the exposure draft
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R). The exposure draft, if
adopted in its current form, would make a significant change to
the existing rules by requiring recognition in the balance sheet
of the overfunded or underfunded positions of defined benefit
pension and other postretirement plans, along with a
corresponding noncash, after-tax adjustment to
stockholders equity. The proposed standard, if adopted,
will be effective for fiscal 2007. We are monitoring the status
of the exposure draft and assessing the impact it will have on
our financial position, results of operations and cash flows.
In June 2006, the Emerging Issues Task Force (EITF) ratified
EITF Issue No.
06-3, How
Taxes Collected from Customers and Remitted to Governmental
Authorities Should Be Presented in the Income Statement (That
Is, Gross versus Net Presentation). The EITF reached a
consensus that the scope of this issue includes any tax assessed
by a governmental authority that is directly imposed on a
revenue-producing transaction between a seller and a customer
and may include sales, use, value added, and some excise taxes.
The EITF also reached a consensus that entities may present
these taxes on either a gross or net basis. If the taxes are
significant, an entity should disclose its policy of presenting
taxes and the amounts of taxes that are recognized on a gross
basis in interim and annual financial statements. We will be
required to apply the provisions of
EITF 06-3
beginning January 1, 2007. We are currently evaluating the
impact this standard may have on our financial position, results
of operations and cash flows.
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation
of FASB Statement No. 109 (FIN 48). FIN 48
clarifies the accounting for uncertainty in income taxes by
establishing standards for measurement and recognition in
financial statements of positions taken by an entity in its
income tax returns. This interpretation also provides guidance
on derecognition of income tax assets and
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
liabilities, classification of current and deferred income tax
assets and liabilities, accounting for interest and penalties,
accounting for income taxes in interim periods and income tax
disclosures. We will be required to apply the provisions of
FIN 48 beginning October 1, 2007. We are currently
evaluating the impact this standard may have on our financial
position, results of operations and cash flows.
|
|
3.
|
Derivative
Instruments and Hedging Activities
|
We conduct risk management activities through both our utility
and natural gas marketing segments. We record our derivatives as
a component of risk management assets and liabilities, which are
classified as current or noncurrent other assets or liabilities
based upon the anticipated settlement date of the underlying
derivative. Our determination of the fair value of these
derivative financial instruments reflects the estimated amounts
that we would receive or pay to terminate or close the contracts
at the reporting date, taking into account the current
unrealized gains and losses on open contracts. In our
determination of fair value, we consider various factors,
including closing exchange and
over-the-counter
quotations, time value and volatility factors underlying the
contracts. Effective October 1, 2005, the Company changed
its mark to market measurement from Inside FERC to Gas Daily to
better reflect the prices of our physical commodity. This change
did not have a material impact on our financial position on the
date of adoption.
The following table shows the fair values of our risk management
assets and liabilities by segment at June 30, 2006 and
September 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
June 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management
activities, current
|
|
$
|
11,930
|
|
|
$
|
4,589
|
|
|
$
|
16,519
|
|
Assets from risk management
activities, noncurrent
|
|
|
|
|
|
|
38
|
|
|
|
38
|
|
Liabilities from risk management
activities, current
|
|
|
(4,299
|
)
|
|
|
(25,351
|
)
|
|
|
(29,650
|
)
|
Liabilities from risk management
activities, noncurrent
|
|
|
|
|
|
|
(9,073
|
)
|
|
|
(9,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
7,631
|
|
|
$
|
(29,797
|
)
|
|
$
|
(22,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management
activities, current
|
|
$
|
93,310
|
|
|
$
|
14,603
|
|
|
$
|
107,913
|
|
Assets from risk management
activities, noncurrent
|
|
|
|
|
|
|
735
|
|
|
|
735
|
|
Liabilities from risk management
activities, current
|
|
|
|
|
|
|
(61,920
|
)
|
|
|
(61,920
|
)
|
Liabilities from risk management
activities, noncurrent
|
|
|
|
|
|
|
(15,316
|
)
|
|
|
(15,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
93,310
|
|
|
$
|
(61,898
|
)
|
|
$
|
31,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Hedging Activities
We use a combination of storage, fixed physical contracts and
fixed financial contracts to partially insulate us and our
customers against gas price volatility during the winter heating
season. Because the gains or losses of financial derivatives
used in our utility segment ultimately will be recovered through
our rates, current period changes in the assets and liabilities
from these risk management activities are recorded as a
component of deferred gas costs in accordance with SFAS 71,
Accounting for the Effects of Certain Types of
Regulation. Accordingly, there is no earnings impact to our
utility segment as a result of the use of financial derivatives.
Our utility hedging activities also include the cost of our
Treasury lock agreements which are described in further detail
below.
12
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Nonutility
Hedging Activities
AEM manages its exposure to the risk of natural gas price
changes through a combination of storage and financial
derivatives, including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. Our financial derivative activities include fair
value hedges to offset changes in the fair value of our natural
gas inventory and cash flow hedges to offset anticipated
purchases and sales of gas in the future. AEM also utilizes
basis swaps and other non-hedge derivative instruments to manage
its exposure to market volatility.
For the three and nine-month periods ended June 30, 2006,
the change in the deferred hedging position in accumulated other
comprehensive loss was attributable to decreases in future
commodity prices relative to the commodity prices stipulated in
the derivative contracts, and the recognition for the nine
months ended June 30, 2006 of $3.4 million in net
deferred hedging gains ($4.8 million in net deferred
hedging losses during the three months ended June 30,
2006) in net income when the derivative contracts matured
according to their terms. The net deferred hedging loss
associated with open cash flow hedges remains subject to market
price fluctuations until the positions are either settled under
the terms of the hedge contracts or terminated prior to
settlement. The majority of the deferred hedging balance as of
June 30, 2006 is expected to be recognized in net income in
fiscal 2006 along with the corresponding hedged purchases and
sales of natural gas. The remainder of the deferred hedging
balance is expected to be recognized in net income in fiscal
2007 and beyond.
Under our risk management policies, we seek to match our
financial derivative positions to our physical storage positions
as well as our expected current and future sales and purchase
obligations to maintain no open positions at the end of each
trading day. The determination of our net open position as of
any day, however, requires us to make assumptions as to future
circumstances, including the use of gas by our customers in
relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. We may also be affected by intraday
fluctuations of gas prices, since the price of natural gas
purchased or sold for future delivery earlier in the day may not
be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on June 30, 2006, AEH
had no net open positions (including existing storage).
Treasury
Activities
During fiscal 2004, we entered into four Treasury lock
agreements to fix the Treasury yield component of the interest
cost of financing associated with the then anticipated issuance
of $875 million of long-term debt in October 2004. We
designated these Treasury lock agreements as cash flow hedges of
an anticipated transaction. These Treasury lock agreements were
settled in October 2004 with a net $43.8 million payment to
the counterparties. This payment was recorded in accumulated
other comprehensive loss and is being recognized as a component
of interest expense over a period of five to ten years. During
the three and nine-month periods ended June 30, 2006, we
recognized approximately $1.4 million and $4.2 million
of this amount as a component of interest expense.
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-term
debt
Long-term debt at June 30, 2006 and September 30, 2005
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Unsecured floating rate Senior
Notes, due October 2007
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
Unsecured 4.00% Senior Notes,
due 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 5.95% Senior Notes,
due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A, 1995-2, 6.27%, due
2010
|
|
|
10,000
|
|
|
|
10,000
|
|
Series A, 1995-1, 6.67%, due
2025
|
|
|
10,000
|
|
|
|
10,000
|
|
Unsecured 6.75% Debentures,
due 2028
|
|
|
150,000
|
|
|
|
150,000
|
|
First Mortgage Bonds
Series P, 10.43% due 2013
|
|
|
8,750
|
|
|
|
10,000
|
|
Other term notes due in
installments through 2013
|
|
|
6,471
|
|
|
|
7,839
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,187,524
|
|
|
|
2,190,142
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on
unsecured senior notes and debentures
|
|
|
(3,441
|
)
|
|
|
(3,774
|
)
|
Current maturities
|
|
|
(3,331
|
)
|
|
|
(3,264
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,180,752
|
|
|
$
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
Our unsecured floating rate debt bears interest at a rate equal
to the three-month LIBOR rate plus 0.375 percent per year.
At June 30, 2006, the interest rate on our floating rate
debt was 5.452 percent.
Short-term
debt
At June 30, 2006 and September 30, 2005, there was
$297.1 million and $144.8 million outstanding under
our commercial paper program and bank credit facilities.
Credit
facilities
We maintain both committed and uncommitted credit facilities.
Borrowings under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas and the
increased gas supplies required to meet customers needs
during periods of cold weather.
Committed
credit facilities
As of June 30, 2006, we had three short-term committed
revolving credit facilities totaling $918 million. The
first facility is a three-year unsecured facility, expiring
October 2008, for $600 million that bears interest at a
base rate or at the LIBOR rate plus from 0.40 percent to
1.00 percent, based on the Companys credit ratings,
and serves
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
as a backup liquidity facility for our $600 million
commercial paper program. At June 30, 2006, there was
$281.9 million outstanding under our commercial paper
program.
We have a second unsecured facility in place which is a
364-day
facility expiring November 2006, for $300 million that
bears interest at a base rate or the LIBOR rate plus from
0.40 percent to 1.00 percent, based on the
Companys credit ratings. At June 30, 2006, there were
no borrowings under this facility.
We have a third unsecured facility in place for $18 million
that bears interest at the Federal Funds rate plus
0.5 percent. This facility expired on March 31, 2006
and was renewed effective April 1, 2006 for one year with
no material changes to its terms and pricing. At June 30,
2006, there was $15.2 million outstanding under this
facility.
The availability of funds under our credit facilities is subject
to conditions specified in the respective credit agreements, all
of which we currently satisfy. These conditions include our
compliance with financial covenants and the continued accuracy
of representations and warranties contained in these agreements.
We are required by the financial covenants in both our
$600 million three-year credit facility and
$300 million
364-day
credit facility to maintain, at the end of each fiscal quarter,
a ratio of total debt to total capitalization of no greater than
70 percent. At June 30, 2006, our
total-debt-to-total-capitalization
ratio, as defined, was 62 percent. In addition, the fees
that we pay on unused amounts under both the $600 million
and $300 million credit facilities are subject to
adjustment depending upon our credit ratings.
Uncommitted
credit facilities
On November 28, 2005, AEM amended its $250 million
uncommitted demand working capital credit facility to increase
the amount of credit available from $250 million to a
maximum of $580 million. On March 31, 2006, AEM
amended and extended this uncommitted demand working capital
credit facility to March 31, 2007.
Borrowings under the credit facility can be made either as
revolving loans or offshore rate loans. Revolving loan
borrowings will bear interest at a floating rate equal to a base
rate (defined as the higher of 0.50 percent per annum above
the Federal Funds rate or the lenders prime rate) plus
0.25 percent. Offshore rate loan borrowings will bear
interest at a floating rate equal to a base rate based upon
LIBOR plus an applicable margin, ranging from 1.25 percent
to 1.625 percent per annum, depending on the excess
tangible net worth of AEM, as defined in the credit facility.
Borrowings drawn down under letters of credit issued by the
banks will bear interest at a floating rate equal to the base
rate, as defined above, plus an applicable margin, which will
range from 1.00 percent to 1.875 percent per annum,
depending on the excess tangible net worth of AEM and whether
the letters of credit are swap-related standby letters of credit.
AEM is required by the financial covenants in the credit
facility to maintain a maximum ratio of total liabilities to
tangible net worth of 5 to 1, along with minimum levels of
net working capital ranging from $20 million to
$120 million. Additionally, AEM must maintain a minimum
tangible net worth ranging from $21 million to
$121 million, and must not have a maximum cumulative loss
from March 30, 2005 exceeding $4 million to
$23 million, depending on the total amount of borrowing
elected from time to time by AEM. At June 30, 2006,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 1.00 to 1.
At June 30, 2006, there were no borrowings outstanding
under this credit facility. However, at June 30, 2006, AEM
letters of credit totaling $70.4 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 $129.6 million at June 30, 2006. This line of
credit is collateralized by substantially all of the assets of
AEM and is guaranteed by AEH.
The Company also has an unsecured short-term uncommitted credit
line for $25 million that is used for working-capital and
letter-of-credit
purposes. There were no borrowings under this uncommitted credit
facility at June 30, 2006, but letters of credit reduced
the amount available by $4.5 million. This uncommitted line
is renewed
15
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
or renegotiated at least annually with varying terms, and we pay
no fee for the availability of the line. Borrowings under this
line are made on a
when-and-as-available
basis at the discretion of the bank.
AEH, the parent company of AEM, has a $100 million
intercompany uncommitted demand credit facility with the Company
which bears interest at LIBOR plus 2.75 percent. This
facility has been approved by our state regulators through
December 31, 2006. At June 30, 2006,
$88.4 million was outstanding under this facility. On
July 1, 2006, this facility was renewed for one year with
no material changes to its terms.
In addition, AEM has a $120 million intercompany
uncommitted demand credit facility with AEH for its nonutility
business which bears interest at LIBOR plus 2.75 percent.
Any outstanding amounts under this facility are subordinated to
AEMs $580 million uncommitted demand credit facility
described above. This facility is used to supplement AEMs
$580 million credit facility. At June 30, 2006,
$82.0 million was outstanding under this facility. On
July 1, 2006, this facility was renewed for one year with
no material changes to its terms.
Debt
Covenants
We have other covenants in addition to those described above.
Our Series P First Mortgage Bonds contain provisions that
allow us to prepay the outstanding balance in whole at any time,
after November 2007, subject to a prepayment premium. The First
Mortgage Bonds provide for certain cash flow requirements and
restrictions on additional indebtedness, sale of assets and
payment of dividends. Under the most restrictive of such
covenants, cumulative cash dividends paid after
December 31, 1985 may not exceed the sum of accumulated net
income for periods after December 31, 1985 plus
$9 million. At June 30, 2006 approximately
$223.0 million of retained earnings was unrestricted with
respect to the payment of dividends.
We were in compliance with all of our debt covenants as of
June 30, 2006. If we were unable to comply with our debt
covenants, we could be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions. Our two public debt indentures relating to
our senior notes and debentures, as well as our
$600 million and $300 million revolving credit
agreements, each contain a default provision that is triggered
if outstanding indebtedness arising out of any other credit
agreements in amounts ranging from in excess of $15 million
to in excess of $100 million becomes due by acceleration or
is not paid at maturity. In addition, AEMs credit
agreement contains a cross-default provision whereby AEM would
be in default if it defaults on other indebtedness, as defined,
by at least $250 thousand in the aggregate. Additionally, this
agreement contains a provision that would limit the amount of
credit available if Atmos were downgraded below an S&P
rating of BBB and a Moodys rating of Baa2.
Except as described above, we have no triggering events in our
debt instruments that are tied to changes in specified credit
ratings or stock price, nor have we entered into any
transactions that would require us to issue equity, based on our
credit rating or other triggering events.
|
|
5.
|
Stock-Based
Compensation
|
Stock-Based
Compensation Plans
On August 12, 1998, the Board of Directors approved and
adopted the 1998 Long-Term Incentive Plan, which became
effective October 1, 1998 after approval by our
shareholders. The Long-Term Incentive Plan is a comprehensive,
long-term incentive compensation plan providing for
discretionary awards of incentive stock options, non-qualified
stock options, stock appreciation rights, bonus stock,
time-lapse restricted stock, performance-based restricted stock
units and stock units to certain employees and non-employee
directors of Atmos and its subsidiaries. The objectives of this
plan include attracting and retaining the best personnel,
providing for additional performance incentives and promoting
our success by providing employees with the opportunity to
acquire common stock. We are authorized to grant awards for up
to a maximum of four million shares of common stock under this
plan subject to certain adjustment provisions. As of
June 30, 2006, non-qualified stock options, bonus stock,
time-lapse restricted stock, performance-based restricted stock
units and stock units had been issued
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
under this plan and 715,699 shares were available for
issuance. The option price of the stock options issued under
this plan is equal to the market price of our stock at the date
of grant. These stock options expire 10 years from the date
of the grant and vest annually over a service period ranging
from one to three years.
We used the Black-Scholes pricing model to estimate the fair
value of each option granted with the following weighted average
assumptions:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
Valuation
Assumptions(1)
|
|
2006
|
|
|
2005
|
|
|
Expected Life
(years)(2)
|
|
|
7
|
|
|
|
7
|
|
Interest
rate(3)
|
|
|
4.6
|
%
|
|
|
4.2
|
%
|
Volatility(4)
|
|
|
20.3
|
%
|
|
|
21.3
|
%
|
Dividend yield
|
|
|
4.8
|
%
|
|
|
4.8
|
%
|
|
|
|
(1) |
|
Beginning on the date of adoption of SFAS 123(R),
forfeitures are estimated based on historical experience. Prior
to the date of adoption, forfeitures were recorded as they
occurred. |
|
(2) |
|
The expected life of stock options is estimated based on
historical experience. |
|
(3) |
|
The interest rate is based on the U.S. Treasury constant
maturity interest rate whose term is consistent with the
expected life of the stock options. |
|
(4) |
|
The volatility is estimated based on historical and current
stock data for the Company. |
A summary of option activity as of June 30, 2006, and
changes during the nine months then ended, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
|
|
|
|
Number
|
|
|
Average
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
of
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
Options
|
|
|
Price
|
|
|
Term
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
(In years)
|
|
|
(In thousands)
|
|
|
Outstanding at September 30,
2005
|
|
|
964,704
|
|
|
$
|
22.20
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
93,196
|
|
|
|
26.19
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(23,186
|
)
|
|
|
22.36
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(166
|
)
|
|
|
21.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2006
|
|
|
1,034,548
|
|
|
$
|
22.56
|
|
|
|
5.6
|
|
|
$
|
3,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at June 30, 2006
|
|
|
1,009,174
|
|
|
$
|
22.47
|
|
|
|
5.5
|
|
|
$
|
3,665
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The stock options had a weighted-average fair value per share on
the date of grant of $3.74 and $3.69 for the nine months ended
June 30, 2006 and 2005. There were no stock options granted
during the three months ended June 30, 2006 and 2005. Net
cash proceeds from the exercise of stock options during the nine
months ended June 30, 2006 and 2005 were $0.5 million
and $10.1 million and during the three months ended
June 30, 2006 and 2005 were $0.5 and $1.0 million. The
associated income tax benefit from stock options exercised
during the nine months ended June 30, 2006 and 2005 was
less than $0.1 million and $1.1 million, and during
the three months ended June 30, 2006 and 2005 was less than
$0.1 million and $0.1 million. The total intrinsic
value of options exercised during the nine months ended
June 30, 2006 and 2005 was less than $0.1 million and
$1.7 million, and during the three months ended
June 30, 2006 and 2005 was less than $0.1 million and
$0.2 million.
As of June 30, 2006, there was less than $0.1 million
of total unrecognized compensation cost related to nonvested
stock options. That cost is expected to be recognized over a
weighted-average period of 1.5 years.
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Restricted
Stock Plans
As noted above, the 1998 Long-Term Incentive Plan provides for
discretionary awards of time-lapse restricted stock and
performance-based restricted stock units to help attract, retain
and reward employees and non-employee directors of Atmos and its
subsidiaries. Certain of these awards vest based upon the
passage of time and other awards vest based upon the passage of
time and the achievement of specified performance targets. The
associated expense is recognized ratably over the vesting period.
A summary of the status of the Companys nonvested
restricted shares as of June 30, 2006, and changes during
the nine months then ended, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
Number of
|
|
|
Average
|
|
|
|
Restricted
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at September 30,
2005
|
|
|
592,490
|
|
|
$
|
25.32
|
|
Granted
|
|
|
440,016
|
|
|
|
26.80
|
|
Vested
|
|
|
(110,347
|
)
|
|
|
22.66
|
|
Forfeited
|
|
|
(10,983
|
)
|
|
|
26.79
|
|
|
|
|
|
|
|
|
|
|
Nonvested at June 30, 2006
|
|
|
911,176
|
|
|
$
|
26.34
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2006, there was $16.0 million of total
unrecognized compensation cost related to nonvested restricted
shares granted under the 1998 Long-Term Incentive Plan. That
cost is expected to be recognized over a weighted-average period
of 2.1 years. The total fair value of restricted stock
vested during the nine months ended June 30, 2006 and 2005
was $2.5 million and $0.5 million, and during the
three months ended June 30, 2006 was $0.9 million.
There were no restricted stock grants that vested during the
three months ended June 30, 2005.
Basic and diluted earnings per share for the three and nine
months ended June 30, 2006 and 2005 are calculated as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
For the
|
|
|
|
Three Months
|
|
|
Nine Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Net income (loss)
|
|
$
|
(18,145
|
)
|
|
$
|
4,486
|
|
|
$
|
141,678
|
|
|
$
|
152,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per
share weighted average common shares
|
|
|
80,840
|
|
|
|
79,683
|
|
|
|
80,520
|
|
|
|
78,009
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
|
|
|
|
330
|
|
|
|
394
|
|
|
|
325
|
|
Stock options
|
|
|
|
|
|
|
131
|
|
|
|
99
|
|
|
|
144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per
share weighted average common shares
|
|
|
80,840
|
|
|
|
80,144
|
|
|
|
81,013
|
|
|
|
78,478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per
share basic
|
|
$
|
(0.22
|
)
|
|
$
|
0.06
|
|
|
$
|
1.76
|
|
|
$
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per
share diluted
|
|
$
|
(0.22
|
)
|
|
$
|
0.06
|
|
|
$
|
1.75
|
|
|
$
|
1.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
There were approximately 396,000 restricted and other shares and
approximately 102,000 stock options that were excluded from the
calculation of diluted earnings per share for the three months
ended June 30, 2006 as their inclusion in the computation
would be anti-dilutive.
There were no
out-of-the-money
options excluded from the computation of diluted earnings per
share for the three and nine months ended June 30, 2006 and
2005 as their exercise price was less than the average market
price of the common stock during that period.
|
|
7.
|
Interim
Pension and Other Postretirement Benefit Plan
Information
|
The components of our net periodic pension cost for our pension
and other postretirement benefit plans for the three and nine
months ended June 30, 2006 and 2005 are presented in the
following tables. All of these costs are recoverable through our
gas utility rates; however, a portion of these costs is
capitalized into our utility rate base. The remaining costs are
recorded as a component of operation and maintenance expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension
cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
4,117
|
|
|
$
|
3,136
|
|
|
$
|
3,271
|
|
|
$
|
2,478
|
|
Interest cost
|
|
|
5,722
|
|
|
|
6,017
|
|
|
|
2,210
|
|
|
|
2,366
|
|
Expected return on assets
|
|
|
(6,400
|
)
|
|
|
(6,885
|
)
|
|
|
(547
|
)
|
|
|
(518
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
1
|
|
|
|
378
|
|
|
|
378
|
|
Amortization of prior service cost
|
|
|
16
|
|
|
|
(2
|
)
|
|
|
90
|
|
|
|
96
|
|
Amortization of actuarial loss
|
|
|
3,299
|
|
|
|
1,891
|
|
|
|
320
|
|
|
|
151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
6,754
|
|
|
$
|
4,158
|
|
|
$
|
5,722
|
|
|
$
|
4,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension
cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
12,351
|
|
|
$
|
9,408
|
|
|
$
|
9,813
|
|
|
$
|
7,434
|
|
Interest cost
|
|
|
17,166
|
|
|
|
18,051
|
|
|
|
6,630
|
|
|
|
7,098
|
|
Expected return on assets
|
|
|
(19,200
|
)
|
|
|
(20,655
|
)
|
|
|
(1,641
|
)
|
|
|
(1,554
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
3
|
|
|
|
1,134
|
|
|
|
1,134
|
|
Amortization of prior service cost
|
|
|
48
|
|
|
|
(6
|
)
|
|
|
270
|
|
|
|
288
|
|
Amortization of actuarial loss
|
|
|
9,897
|
|
|
|
5,673
|
|
|
|
960
|
|
|
|
453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
20,262
|
|
|
$
|
12,474
|
|
|
$
|
17,166
|
|
|
$
|
14,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three and nine months ended June 30, 2006 and 2005
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.50
|
%
|
|
|
8.75
|
%
|
|
|
5.30
|
%
|
|
|
5.30
|
%
|
19
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The discount rate used to compute the present value of a
plans liabilities generally is based on rates of
high-grade corporate bonds with maturities similar to the
average period over which the benefits will be paid. During the
nine months ended June 30, 2006, we contributed
$2.8 million to the Atmos Energy Corporation Retirement
Plan for Mississippi Valley Gas Union Employees. The current
year contribution achieved a desired level of funding by
satisfying the minimum funding requirements while maximizing the
tax deductible contribution for this plan for plan year 2005. We
anticipate making no additional contributions to our pension
plans for the remainder of fiscal 2006. However, we contributed
$7.9 million to our other postretirement plans, and we
expect to contribute approximately $12 million to these
plans during fiscal 2006.
|
|
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 13 to our annual report on
Form 10-K
for the year ended September 30, 2005, there were no
material changes in the status of such litigation and
environmental-related matters or claims during the nine months
ended June 30, 2006. 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 net 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 net cash flows.
Purchase
Commitments
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At June 30, 2006, AEM was committed to
purchase 64.8 Bcf within one year, 53.7 Bcf within one
to three years and 3.1 Bcf after three years under indexed
contracts. AEM is committed to purchase 2.7 Bcf within one
year and 0.2 Bcf within one to three years under fixed
price contracts with prices ranging from $5.45 to $12.00.
Purchases under these contracts totaled $398.9 million and
$294.0 million for the three months ended June 30,
2006 and 2005 and $1,718.4 million and $999.4 million
for the nine months ended June 30, 2006 and 2005.
Our utility operations, other than the Mid-Tex Division,
maintain supply contracts with several vendors that generally
cover a period of up to one year. Commitments for estimated base
gas volumes are established under these contracts on a monthly
basis at contractually negotiated prices. Commitments for
incremental daily purchases are made as necessary during the
month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
prices. The estimated fiscal year commitments under these
contracts as of June 30, 2006 are as follows (in thousands):
|
|
|
|
|
2006
|
|
$
|
70,864
|
|
2007
|
|
|
346,837
|
|
2008
|
|
|
115,004
|
|
2009
|
|
|
12,795
|
|
2010
|
|
|
12,479
|
|
Thereafter
|
|
|
39,812
|
|
|
|
|
|
|
|
|
$
|
597,791
|
|
|
|
|
|
|
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Regulatory
Matters
In February 2005, the Attorney General of the State of Kentucky
filed a complaint with the Kentucky Public Service Commission
(KPSC) alleging that our rates were producing revenues in excess
of reasonable levels. We answered the complaint and filed a
Motion to Dismiss with the KPSC. On February 2, 2006, the
KPSC issued an Order denying our Motion to Dismiss and on
March 3, 2006 set a procedural schedule for the case. The
Attorney General is currently conducting discovery. A hearing
should be scheduled for early 2007. We believe that the Attorney
General will not be able to demonstrate that our present rates
are in excess of reasonable levels.
In May 2006, the Mid-Tex Division filed a Statement of Intent
seeking incremental annual revenues of $60 million and
several rate design changes including Weather Normalization
Adjustment (WNA), revenue stabilization, and recovery of the gas
cost component of bad debt. The Statement of Intent consolidated
show cause resolutions that had been filed in
approximately 80 cities served by the Mid-Tex Division,
including the City of Dallas, which requires the Mid-Tex
Division to demonstrate that existing distribution rates are
just and reasonable.
In July 2006, the Mid-Tex Division and the Railroad Commission
of Texas (RRC) agreed to implement WNA on both an interim and
permanent basis, effective October 1, 2006. The agreement
provided that the interim WNA will use 30 years of weather
history, while the permanent WNA would allow the parties to
contest the appropriate period of weather data to use in
calculating normal weather. The permanent WNA would also be
modified or adjusted to conform to the rate design that the RRC
ultimately approves in the case, which is anticipated no later
than the first quarter of calendar 2007. Any rate increase will
be effective prospectively from the date of the final order;
however, any rate decrease will be effective from May 31,
2006.
In November 2005, we received a notice from the Tennessee
Regulatory Authority (TRA) that it was opening an investigation
into allegations by the Consumer Advocate and Protection
Division of the Tennessee Attorney Generals Office that we
are overcharging customers in parts of Tennessee by
approximately $10 million per year. We have responded to
numerous data requests from the TRA Staff. On April 24,
2006, the TRA Staff filed a Report and Recommendation in which
it recommended that the TRA convene a contested case procedure
for the purpose of establishing a fair and reasonable return.
The TRA convened to consider the Staffs recommendation on
May 15, 2006 and set a procedural schedule. All parties
filed direct testimony on July 17, 2006, with rebuttal due
August 18, 2006. A hearing is scheduled for August 29,
2006. We believe that the Consumer Advocate and Protection
Division will not be able to demonstrate that our present rates
are in excess of reasonable levels.
In January 2006, the Lubbock, Texas City Council passed a
resolution requiring Atmos to submit copies of all documentation
necessary for the city to review the rates of Atmos West
Texas Division to ensure they are just and reasonable.
Information was provided to the city on February 28, 2006.
We believe that we will be able to ultimately demonstrate to the
City of Lubbock that our rates are just and reasonable.
In May 2006, Atmos began receiving show cause
ordinances from several of the cities in the West Texas
Division. The ordinances request a filing to be made no later
than September 15, 2006. We believe that we will be able to
ultimately demonstrate to the West Texas cities that our rates
are just and reasonable.
Other
On November 30, 2005, we entered into an agreement with a
third party to jointly construct, own and operate a
45-mile
large diameter natural gas pipeline in the northern portion of
the Dallas/Fort Worth Metroplex (North Side Loop). Under
the terms of the agreement, we are responsible for contributing
no more than $42.5 million to the construction costs of the
pipeline. We are also responsible for 50 percent of the
costs of the compression facilities. The North Side Loop was
fully placed into service in May 2006. As of June 30, 2006,
we had spent $46.1 million for the North Side Loop project
and expect to spend approximately $5.3 million in the
remainder of fiscal 2006 for this project.
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During the third quarter of fiscal 2005, we entered into two
agreements with third parties to transport natural gas through
our Texas intrastate pipeline system beginning in fiscal 2006.
To handle the increased volumes for these projects, we installed
compression equipment and other pipeline infrastructure. We have
spent approximately $30 million in fiscal 2006 for these
projects, which were placed in service at the end of the third
quarter of fiscal 2006.
On August 29, 2005, Hurricane Katrina struck the Gulf
Coast, inflicting significant damage to our eastern Louisiana
operations. The hardest hit areas in our service territory were
in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes.
In total, approximately 230,000 of our natural gas customers
were affected in these areas. Although service has been restored
for many of our customers, a significant number of customers
will not require gas service for some time because of sustained
damages. We cannot predict with certainty how many of these
customers will return to these service areas and over what time
period they may return. Additionally, we cannot accurately
determine what regulatory actions, if any, may be taken by the
regulators with respect to these areas. We are implementing new
rates, subject to refund, in August 2006 that reflect the
reduced customer count and enable us to recoup costs
attributable to Hurricane Katrina.
In May 2006, we announced plans to form a joint venture with a
local natural gas producer to construct a natural gas gathering
system in Eastern Kentucky that will originate in Floyd County,
Kentucky, and extend north approximately 65 miles to
interconnect with the Tennessee Gas Pipeline in Carter County,
Kentucky. Tennessee Gas Pipelines interstate system
delivers natural gas to the northeastern United States,
including New York City and Boston. The new system is expected
to relieve severe gas gathering and transportation constraints
that historically have burdened natural gas producers in the
area and should improve delivery reliability to natural gas
customers. More than a dozen other producers have signed
memoranda of understanding to commit gas volumes to the new
system and to enter into agreements on commercially reasonable
terms.
The project is expected to cost between $75 million to
$80 million. Upon receiving all required regulatory
approvals, construction is expected to begin in the first half
of fiscal 2007, with operations expected to begin in fiscal
2008. Final terms of the joint venture are still under
negotiation; however, we anticipate that we will have the
ability to consolidate the joint venture.
|
|
9.
|
Concentration
of Credit Risk
|
Credit risk is the risk of financial loss to us if a customer
fails to perform its contractual obligations. We engage in
transactions for the purchase and sale of products and services
with major companies in the energy industry and with industrial,
commercial, residential and municipal energy consumers. These
transactions principally occur in the southern and midwestern
regions of the United States. We believe that this geographic
concentration does not contribute significantly to our overall
exposure to credit risk. Credit risk associated with trade
accounts receivable for the utility segment is mitigated by the
large number of individual customers and diversity in our
customer base.
Customer diversification also helps mitigate AEMs exposure
to credit risk. AEM maintains credit policies with respect to
its counterparties that it believes minimizes overall credit
risk. Where appropriate, such policies include the evaluation of
a prospective counterpartys financial condition,
collateral requirements and the use of standardized agreements
that facilitate the netting of cash flows associated with a
single counterparty. AEM also monitors the financial condition
of existing counterparties on an ongoing basis. Customers not
meeting minimum standards are required to provide adequate
assurance of financial performance.
AEM maintains a provision for credit losses based upon factors
surrounding the credit risk of customers, historical trends and
other information. We believe, based on our credit policies and
our provisions for credit losses, that our financial position,
results of operations and cash flows will not be materially
affected as a result of nonperformance by any single
counterparty.
AEMs estimated credit exposure is monitored in terms of
the percentage of its customers that are rated as investment
grade versus non-investment grade. Credit exposure is defined as
the total of (1) accounts receivable,
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(2) delivered, but unbilled physical sales and
(3) mark-to-market
exposure for sales and purchases. Investment grade
determinations are set internally by AEMs credit
department, but are primarily based on external ratings provided
by Moodys Investors Service Inc. (Moodys)
and/or
Standard & Poors Corporation (S&P). For
non-rated entities, the default rating for municipalities is
investment grade, while the default rating for non-guaranteed
industrial and commercial customers is non-investment grade. The
following table shows the percentages related to the investment
ratings as of June 30, 2006 and September 30, 2005.
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
Investment grade
|
|
|
41
|
%
|
|
|
49
|
%
|
Non-investment grade
|
|
|
59
|
%
|
|
|
51
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
The following table presents our derivative counterparty credit
exposure by operating segment based upon the unrealized fair
value of our derivative contracts that represent assets as of
June 30, 2006. Investment grade counterparties have minimum
credit ratings of BBB-, assigned by S&P; or Baa3, assigned
by Moodys. Non-investment grade counterparties are
composed of counterparties that are below investment grade or
that have not been assigned an internal investment grade rating
due to the short-term nature of the contracts associated with
that counterparty. This category is composed of numerous smaller
counterparties, none of which is individually significant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2006
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
|
|
|
|
Segment(1)
|
|
|
Segment
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Investment grade counterparties
|
|
$
|
11,930
|
|
|
$
|
843
|
|
|
$
|
12,773
|
|
Non-investment grade counterparties
|
|
|
|
|
|
|
3,784
|
|
|
|
3,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,930
|
|
|
$
|
4,627
|
|
|
$
|
16,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Counterparty risk for our utility segment is minimized because
hedging gains and losses are passed through to our customers. |
Atmos Energy Corporation and its subsidiaries are engaged
primarily in the natural gas utility business as well as certain
nonutility businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 million residential, commercial, public authority and
industrial customers throughout our seven regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses we provide natural gas
management and marketing services to industrial customers,
municipalities and other local distribution companies located in
22 states. Additionally, we provide natural gas
transportation and storage services to certain of our utility
operations and to third parties.
Our operations are divided into four segments:
|
|
|
|
|
the utility segment, which includes our regulated natural gas
distribution and related sales operations,
|
|
|
|
the natural gas marketing segment, which includes a variety of
nonregulated natural gas management services,
|
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
the pipeline and storage segment, which includes our regulated
and nonregulated natural gas transmission and storage
services and
|
|
|
|
the other nonutility segment, which includes all of our other
nonregulated nonutility operations.
|
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 utility segment operations are geographically
dispersed, they are reported as a single segment as each utility
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, 2005. We evaluate
performance based on net income or loss of the respective
operating units.
Income statements for the three and nine-month periods ended
June 30, 2006 and 2005 by segment are presented in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2006
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
401,896
|
|
|
$
|
441,418
|
|
|
$
|
19,597
|
|
|
$
|
332
|
|
|
$
|
|
|
|
$
|
863,243
|
|
Intersegment revenues
|
|
|
148
|
|
|
|
121,029
|
|
|
|
16,265
|
|
|
|
1,081
|
|
|
|
(138,523
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
402,044
|
|
|
|
562,447
|
|
|
|
35,862
|
|
|
|
1,413
|
|
|
|
(138,523
|
)
|
|
|
863,243
|
|
Purchased gas cost
|
|
|
232,192
|
|
|
|
563,333
|
|
|
|
379
|
|
|
|
|
|
|
|
(137,161
|
)
|
|
|
658,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
169,852
|
|
|
|
(886
|
)
|
|
|
35,483
|
|
|
|
1,413
|
|
|
|
(1,362
|
)
|
|
|
204,500
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
85,372
|
|
|
|
5,725
|
|
|
|
13,485
|
|
|
|
1,227
|
|
|
|
(1,429
|
)
|
|
|
104,380
|
|
Depreciation and amortization
|
|
|
41,537
|
|
|
|
466
|
|
|
|
4,807
|
|
|
|
28
|
|
|
|
|
|
|
|
46,838
|
|
Taxes, other than income
|
|
|
45,853
|
|
|
|
273
|
|
|
|
2,272
|
|
|
|
81
|
|
|
|
|
|
|
|
48,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
172,762
|
|
|
|
6,464
|
|
|
|
20,564
|
|
|
|
1,336
|
|
|
|
(1,429
|
)
|
|
|
199,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(2,910
|
)
|
|
|
(7,350
|
)
|
|
|
14,919
|
|
|
|
77
|
|
|
|
67
|
|
|
|
4,803
|
|
Miscellaneous income
|
|
|
3,022
|
|
|
|
556
|
|
|
|
309
|
|
|
|
1,372
|
|
|
|
(4,296
|
)
|
|
|
963
|
|
Interest charges
|
|
|
30,892
|
|
|
|
1,716
|
|
|
|
6,384
|
|
|
|
1,181
|
|
|
|
(4,229
|
)
|
|
|
35,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(30,780
|
)
|
|
|
(8,510
|
)
|
|
|
8,844
|
|
|
|
268
|
|
|
|
|
|
|
|
(30,178
|
)
|
Income tax expense (benefit)
|
|
|
(11,809
|
)
|
|
|
(3,341
|
)
|
|
|
3,012
|
|
|
|
105
|
|
|
|
|
|
|
|
(12,033
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(18,971
|
)
|
|
$
|
(5,169
|
)
|
|
$
|
5,832
|
|
|
$
|
163
|
|
|
$
|
|
|
|
$
|
(18,145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
75,973
|
|
|
$
|
500
|
|
|
$
|
32,988
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
109,461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2005
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
501,481
|
|
|
$
|
387,999
|
|
|
$
|
16,854
|
|
|
$
|
543
|
|
|
$
|
|
|
|
$
|
906,877
|
|
Intersegment revenues
|
|
|
254
|
|
|
|
78,836
|
|
|
|
16,595
|
|
|
|
878
|
|
|
|
(96,563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501,735
|
|
|
|
466,835
|
|
|
|
33,449
|
|
|
|
1,421
|
|
|
|
(96,563
|
)
|
|
|
906,877
|
|
Purchased gas cost
|
|
|
326,502
|
|
|
|
456,440
|
|
|
|
(1,733
|
)
|
|
|
|
|
|
|
(95,606
|
)
|
|
|
685,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
175,233
|
|
|
|
10,395
|
|
|
|
35,182
|
|
|
|
1,421
|
|
|
|
(957
|
)
|
|
|
221,274
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
76,862
|
|
|
|
4,948
|
|
|
|
9,573
|
|
|
|
1,067
|
|
|
|
(1,007
|
)
|
|
|
91,443
|
|
Depreciation and amortization
|
|
|
38,775
|
|
|
|
458
|
|
|
|
4,189
|
|
|
|
26
|
|
|
|
|
|
|
|
43,448
|
|
Taxes, other than income
|
|
|
44,555
|
|
|
|
242
|
|
|
|
2,064
|
|
|
|
54
|
|
|
|
|
|
|
|
46,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
160,192
|
|
|
|
5,648
|
|
|
|
15,826
|
|
|
|
1,147
|
|
|
|
(1,007
|
)
|
|
|
181,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
15,041
|
|
|
|
4,747
|
|
|
|
19,356
|
|
|
|
274
|
|
|
|
50
|
|
|
|
39,468
|
|
Miscellaneous income
|
|
|
3,122
|
|
|
|
153
|
|
|
|
613
|
|
|
|
578
|
|
|
|
(2,942
|
)
|
|
|
1,524
|
|
Interest charges
|
|
|
28,520
|
|
|
|
957
|
|
|
|
6,169
|
|
|
|
935
|
|
|
|
(2,892
|
)
|
|
|
33,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(10,357
|
)
|
|
|
3,943
|
|
|
|
13,800
|
|
|
|
(83
|
)
|
|
|
|
|
|
|
7,303
|
|
Income tax expense (benefit)
|
|
|
(3,689
|
)
|
|
|
1,583
|
|
|
|
4,958
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
2,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(6,668
|
)
|
|
$
|
2,360
|
|
|
$
|
8,842
|
|
|
$
|
(48
|
)
|
|
$
|
|
|
|
$
|
4,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
80,336
|
|
|
$
|
219
|
|
|
$
|
8,830
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
89,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2006
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
3,254,078
|
|
|
$
|
1,866,768
|
|
|
$
|
58,716
|
|
|
$
|
1,347
|
|
|
$
|
|
|
|
$
|
5,180,909
|
|
Intersegment revenues
|
|
|
596
|
|
|
|
616,153
|
|
|
|
62,341
|
|
|
|
3,153
|
|
|
|
(682,243
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,254,674
|
|
|
|
2,482,921
|
|
|
|
121,057
|
|
|
|
4,500
|
|
|
|
(682,243
|
)
|
|
|
5,180,909
|
|
Purchased gas cost
|
|
|
2,488,906
|
|
|
|
2,413,511
|
|
|
|
590
|
|
|
|
|
|
|
|
(678,591
|
)
|
|
|
4,224,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
765,768
|
|
|
|
69,410
|
|
|
|
120,467
|
|
|
|
4,500
|
|
|
|
(3,652
|
)
|
|
|
956,493
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
272,501
|
|
|
|
15,898
|
|
|
|
36,846
|
|
|
|
3,853
|
|
|
|
(3,803
|
)
|
|
|
325,295
|
|
Depreciation and amortization
|
|
|
121,708
|
|
|
|
1,411
|
|
|
|
13,978
|
|
|
|
77
|
|
|
|
|
|
|
|
137,174
|
|
Taxes, other than income
|
|
|
150,456
|
|
|
|
864
|
|
|
|
7,086
|
|
|
|
285
|
|
|
|
|
|
|
|
158,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
544,665
|
|
|
|
18,173
|
|
|
|
57,910
|
|
|
|
4,215
|
|
|
|
(3,803
|
)
|
|
|
621,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
221,103
|
|
|
|
51,237
|
|
|
|
62,557
|
|
|
|
285
|
|
|
|
151
|
|
|
|
335,333
|
|
Miscellaneous income (expense)
|
|
|
6,014
|
|
|
|
1,754
|
|
|
|
1,846
|
|
|
|
3,216
|
|
|
|
(13,858
|
)
|
|
|
(1,028
|
)
|
Interest charges
|
|
|
92,783
|
|
|
|
6,575
|
|
|
|
18,978
|
|
|
|
2,996
|
|
|
|
(13,707
|
)
|
|
|
107,625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
134,334
|
|
|
|
46,416
|
|
|
|
45,425
|
|
|
|
505
|
|
|
|
|
|
|
|
226,680
|
|
Income tax expense
|
|
|
50,264
|
|
|
|
18,201
|
|
|
|
16,339
|
|
|
|
198
|
|
|
|
|
|
|
|
85,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
84,070
|
|
|
$
|
28,215
|
|
|
$
|
29,086
|
|
|
$
|
307
|
|
|
$
|
|
|
|
$
|
141,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
232,137
|
|
|
$
|
1,067
|
|
|
$
|
89,487
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
322,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2005
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
2,649,979
|
|
|
$
|
1,250,507
|
|
|
$
|
58,433
|
|
|
$
|
1,667
|
|
|
$
|
|
|
|
$
|
3,960,586
|
|
Intersegment revenues
|
|
|
814
|
|
|
|
223,020
|
|
|
|
64,252
|
|
|
|
2,391
|
|
|
|
(290,477
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,650,793
|
|
|
|
1,473,527
|
|
|
|
122,685
|
|
|
|
4,058
|
|
|
|
(290,477
|
)
|
|
|
3,960,586
|
|
Purchased gas cost
|
|
|
1,895,181
|
|
|
|
1,425,128
|
|
|
|
8,895
|
|
|
|
|
|
|
|
(287,889
|
)
|
|
|
3,041,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
755,612
|
|
|
|
48,399
|
|
|
|
113,790
|
|
|
|
4,058
|
|
|
|
(2,588
|
)
|
|
|
919,271
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
259,884
|
|
|
|
12,410
|
|
|
|
33,077
|
|
|
|
3,007
|
|
|
|
(2,738
|
)
|
|
|
305,640
|
|
Depreciation and amortization
|
|
|
119,007
|
|
|
|
1,436
|
|
|
|
12,244
|
|
|
|
84
|
|
|
|
|
|
|
|
132,771
|
|
Taxes, other than income
|
|
|
133,395
|
|
|
|
412
|
|
|
|
6,510
|
|
|
|
220
|
|
|
|
|
|
|
|
140,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
512,286
|
|
|
|
14,258
|
|
|
|
51,831
|
|
|
|
3,311
|
|
|
|
(2,738
|
)
|
|
|
578,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
243,326
|
|
|
|
34,141
|
|
|
|
61,959
|
|
|
|
747
|
|
|
|
150
|
|
|
|
340,323
|
|
Miscellaneous income
|
|
|
6,068
|
|
|
|
600
|
|
|
|
1,220
|
|
|
|
1,787
|
|
|
|
(6,808
|
)
|
|
|
2,867
|
|
Interest charges
|
|
|
83,841
|
|
|
|
2,037
|
|
|
|
18,568
|
|
|
|
1,516
|
|
|
|
(6,658
|
)
|
|
|
99,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
165,553
|
|
|
|
32,704
|
|
|
|
44,611
|
|
|
|
1,018
|
|
|
|
|
|
|
|
243,886
|
|
Income tax expense
|
|
|
61,547
|
|
|
|
13,291
|
|
|
|
16,047
|
|
|
|
414
|
|
|
|
|
|
|
|
91,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
104,006
|
|
|
$
|
19,413
|
|
|
$
|
28,564
|
|
|
$
|
604
|
|
|
$
|
|
|
|
$
|
152,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
209,392
|
|
|
$
|
586
|
|
|
$
|
16,873
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
226,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at June 30, 2006 and
September 30, 2005 by segment is presented in the following
tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2006
|
|
|
|
|
|
|
Natural
|
|
|
Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,055,306
|
|
|
$
|
7,381
|
|
|
$
|
515,076
|
|
|
$
|
1,320
|
|
|
$
|
|
|
|
$
|
3,579,083
|
|
Investment in subsidiaries
|
|
|
253,289
|
|
|
|
(2,092
|
)
|
|
|
|
|
|
|
|
|
|
|
(251,197
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
8,865
|
|
|
|
17,456
|
|
|
|
|
|
|
|
528
|
|
|
|
|
|
|
|
26,849
|
|
Cash held on deposit in margin
account
|
|
|
|
|
|
|
58,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58,176
|
|
Assets from risk management
activities
|
|
|
11,930
|
|
|
|
10,388
|
|
|
|
2,698
|
|
|
|
|
|
|
|
(8,497
|
)
|
|
|
16,519
|
|
Other current assets
|
|
|
661,342
|
|
|
|
356,506
|
|
|
|
37,974
|
|
|
|
86,003
|
|
|
|
(193,198
|
)
|
|
|
948,627
|
|
Intercompany receivables
|
|
|
555,423
|
|
|
|
|
|
|
|
|
|
|
|
30,437
|
|
|
|
(585,860
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,237,560
|
|
|
|
442,526
|
|
|
|
40,672
|
|
|
|
116,968
|
|
|
|
(787,555
|
)
|
|
|
1,050,171
|
|
Intangible assets
|
|
|
|
|
|
|
3,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,069
|
|
Goodwill
|
|
|
566,800
|
|
|
|
24,282
|
|
|
|
143,198
|
|
|
|
|
|
|
|
|
|
|
|
734,280
|
|
Noncurrent assets from risk
management activities
|
|
|
|
|
|
|
38
|
|
|
|
2,405
|
|
|
|
|
|
|
|
(2,405
|
)
|
|
|
38
|
|
Deferred charges and other assets
|
|
|
225,647
|
|
|
|
1,334
|
|
|
|
5,232
|
|
|
|
17,623
|
|
|
|
|
|
|
|
249,836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,338,602
|
|
|
$
|
476,538
|
|
|
$
|
706,583
|
|
|
$
|
135,911
|
|
|
$
|
(1,041,157
|
)
|
|
$
|
5,616,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
1,664,556
|
|
|
$
|
127,682
|
|
|
$
|
92,210
|
|
|
$
|
33,397
|
|
|
$
|
(253,289
|
)
|
|
$
|
1,664,556
|
|
Long-term debt
|
|
|
2,176,362
|
|
|
|
|
|
|
|
|
|
|
|
4,390
|
|
|
|
|
|
|
|
2,180,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,840,918
|
|
|
|
127,682
|
|
|
|
92,210
|
|
|
|
37,787
|
|
|
|
(253,289
|
)
|
|
|
3,845,308
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt
|
|
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
2,081
|
|
|
|
|
|
|
|
3,331
|
|
Short-term debt
|
|
|
297,087
|
|
|
|
82,000
|
|
|
|
|
|
|
|
88,407
|
|
|
|
(170,407
|
)
|
|
|
297,087
|
|
Liabilities from risk management
activities
|
|
|
4,299
|
|
|
|
28,049
|
|
|
|
5,795
|
|
|
|
|
|
|
|
(8,493
|
)
|
|
|
29,650
|
|
Other current liabilities
|
|
|
460,479
|
|
|
|
181,275
|
|
|
|
63,386
|
|
|
|
293
|
|
|
|
(20,703
|
)
|
|
|
684,730
|
|
Intercompany payables
|
|
|
|
|
|
|
61,236
|
|
|
|
524,624
|
|
|
|
|
|
|
|
(585,860
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
763,115
|
|
|
|
352,560
|
|
|
|
593,805
|
|
|
|
90,781
|
|
|
|
(785,463
|
)
|
|
|
1,014,798
|
|
Deferred income taxes
|
|
|
280,987
|
|
|
|
(15,434
|
)
|
|
|
16,178
|
|
|
|
2,026
|
|
|
|
|
|
|
|
283,757
|
|
Noncurrent liabilities from risk
management activities
|
|
|
|
|
|
|
11,478
|
|
|
|
|
|
|
|
|
|
|
|
(2,405
|
)
|
|
|
9,073
|
|
Regulatory cost of removal
obligation
|
|
|
275,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
275,955
|
|
Deferred credits and other
liabilities
|
|
|
177,627
|
|
|
|
252
|
|
|
|
4,390
|
|
|
|
5,317
|
|
|
|
|
|
|
|
187,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,338,602
|
|
|
$
|
476,538
|
|
|
$
|
706,583
|
|
|
$
|
135,911
|
|
|
$
|
(1,041,157
|
)
|
|
$
|
5,616,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2005
|
|
|
|
|
|
|
Natural
|
|
|
Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
2,926,096
|
|
|
$
|
7,278
|
|
|
$
|
439,574
|
|
|
$
|
1,419
|
|
|
$
|
|
|
|
$
|
3,374,367
|
|
Investment in subsidiaries
|
|
|
231,342
|
|
|
|
(1,896
|
)
|
|
|
|
|
|
|
|
|
|
|
(229,446
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
10,663
|
|
|
|
28,949
|
|
|
|
|
|
|
|
504
|
|
|
|
|
|
|
|
40,116
|
|
Cash held on deposit in margin
account
|
|
|
4,170
|
|
|
|
76,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80,956
|
|
Assets from risk management
activities
|
|
|
93,310
|
|
|
|
39,528
|
|
|
|
1,739
|
|
|
|
|
|
|
|
(26,664
|
)
|
|
|
107,913
|
|
Other current assets
|
|
|
666,081
|
|
|
|
421,777
|
|
|
|
36,208
|
|
|
|
63,820
|
|
|
|
(152,441
|
)
|
|
|
1,035,445
|
|
Intercompany receivables
|
|
|
505,728
|
|
|
|
|
|
|
|
|
|
|
|
20,133
|
|
|
|
(525,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,279,952
|
|
|
|
567,040
|
|
|
|
37,947
|
|
|
|
84,457
|
|
|
|
(704,966
|
)
|
|
|
1,264,430
|
|
Intangible assets
|
|
|
|
|
|
|
3,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,507
|
|
Goodwill
|
|
|
566,800
|
|
|
|
24,282
|
|
|
|
143,198
|
|
|
|
|
|
|
|
|
|
|
|
734,280
|
|
Noncurrent assets from risk
management activities
|
|
|
|
|
|
|
2,073
|
|
|
|
1,338
|
|
|
|
|
|
|
|
(2,676
|
)
|
|
|
735
|
|
Deferred charges and other assets
|
|
|
249,179
|
|
|
|
1,461
|
|
|
|
5,737
|
|
|
|
19,831
|
|
|
|
|
|
|
|
276,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,253,369
|
|
|
$
|
603,745
|
|
|
$
|
627,794
|
|
|
$
|
105,707
|
|
|
$
|
(937,088
|
)
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
1,602,422
|
|
|
$
|
144,827
|
|
|
$
|
53,426
|
|
|
$
|
33,089
|
|
|
$
|
(231,342
|
)
|
|
$
|
1,602,422
|
|
Long-term debt
|
|
|
2,177,279
|
|
|
|
|
|
|
|
|
|
|
|
5,825
|
|
|
|
|
|
|
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,779,701
|
|
|
|
144,827
|
|
|
|
53,426
|
|
|
|
38,914
|
|
|
|
(231,342
|
)
|
|
|
3,785,526
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term
debt
|
|
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
2,014
|
|
|
|
|
|
|
|
3,264
|
|
Short-term debt
|
|
|
144,809
|
|
|
|
60,000
|
|
|
|
|
|
|
|
51,320
|
|
|
|
(111,320
|
)
|
|
|
144,809
|
|
Liabilities from risk management
activities
|
|
|
|
|
|
|
63,936
|
|
|
|
25,038
|
|
|
|
|
|
|
|
(27,054
|
)
|
|
|
61,920
|
|
Other current liabilities
|
|
|
623,300
|
|
|
|
217,777
|
|
|
|
95,557
|
|
|
|
4,963
|
|
|
|
(38,835
|
)
|
|
|
902,762
|
|
Intercompany payables
|
|
|
|
|
|
|
87,968
|
|
|
|
437,893
|
|
|
|
|
|
|
|
(525,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
769,359
|
|
|
|
429,681
|
|
|
|
558,488
|
|
|
|
58,297
|
|
|
|
(703,070
|
)
|
|
|
1,112,755
|
|
Deferred income taxes
|
|
|
268,108
|
|
|
|
12,369
|
|
|
|
9,563
|
|
|
|
2,167
|
|
|
|
|
|
|
|
292,207
|
|
Noncurrent liabilities from risk
management activities
|
|
|
|
|
|
|
16,654
|
|
|
|
1,338
|
|
|
|
|
|
|
|
(2,676
|
)
|
|
|
15,316
|
|
Regulatory cost of removal
obligation
|
|
|
263,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
263,424
|
|
Deferred credits and other
liabilities
|
|
|
172,777
|
|
|
|
214
|
|
|
|
4,979
|
|
|
|
6,329
|
|
|
|
|
|
|
|
184,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,253,369
|
|
|
$
|
603,745
|
|
|
$
|
627,794
|
|
|
$
|
105,707
|
|
|
$
|
(937,088
|
)
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of June 30, 2006, and the
related condensed consolidated statements of income for the
three-month and nine-month periods ended June 30, 2006 and
2005, and the condensed consolidated statements of cash flows
for the nine-month periods ended June 30, 2006 and 2005.
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, 2005, and the related consolidated statements
of income, shareholders equity, and cash flows for the
year then ended, not presented herein, and in our report dated
November 16, 2005, 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, 2005, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Dallas, Texas
August 7, 2006
30
|
|
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, 2005.
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
the Company 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
the Companys documents or oral presentations, the words
anticipate, believe, expect,
estimate, 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 the Companys strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties include the
following: adverse weather conditions, such as warmer than
normal weather in the Companys gas utility service
territories or colder than normal weather that could adversely
affect our natural gas marketing activities; regulatory trends
and decisions, including deregulation initiatives and the impact
of rate proceedings before various state regulatory commissions;
market risks beyond our control affecting our risk management
activities including market liquidity, commodity price
volatility and counterparty creditworthiness; national, regional
and local economic conditions; the Companys ability to
continue to access the capital markets; the effects of inflation
and changes in the availability and prices of natural gas,
including the volatility of natural gas prices; increased
competition from energy suppliers and alternative forms of
energy; risks relating to the acquisition of the TXU Gas
operations, including without limitation, the Companys
increased indebtedness resulting from the acquisition of the TXU
Gas operations; the impact of recent natural disasters on our
operations, especially Hurricane Katrina; and other
uncertainties, which may be discussed herein, all of which are
difficult to predict and many of which are beyond the control of
the Company. A more detailed discussion of these risks and
uncertainties may be found in the Companys
Form 10-K
for the year ended September 30, 2005. Accordingly, while
the Company believes 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, the Company undertakes no obligation
to update or revise any of its forward-looking statements
whether as a result of new information, future events or
otherwise.
OVERVIEW
Atmos Energy Corporation and its subsidiaries are engaged
primarily in the natural gas utility business as well as certain
nonutility businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 million residential, commercial, public authority and
industrial customers throughout our seven regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses we provide natural gas
management, transportation, storage and marketing services to
industrial customers, municipalities and other local
distribution companies located in 22 states. Additionally,
we provide natural gas transportation and storage services to
certain of our utility operations and to third parties.
Our operations are divided into four segments:
|
|
|
|
|
the utility segment, which includes our regulated natural gas
distribution and related sales operations,
|
31
|
|
|
|
|
the natural gas marketing segment, which includes a variety of
nonregulated natural gas management services,
|
|
|
|
the pipeline and storage segment, which includes our regulated
and nonregulated natural gas transmission and storage
services and
|
|
|
|
the other nonutility segment, which includes all of our other
nonregulated nonutility operations.
|
The following summarizes the results of our operations and other
significant events for the nine months ended June 30, 2006:
|
|
|
|
|
Our utility segment net income decreased by $19.9 million
during the nine months ended June 30, 2006 compared with
the nine months ended June 30, 2005. The decrease reflects
the impact of weather, as adjusted for jurisdictions with
weather-normalized rates, that was three percent warmer than the
prior-year period and 13 percent warmer than normal,
coupled with higher operating expenses.
|
|
|
|
In May 2006, the Louisiana Public Service Commission (LPSC)
approved a settlement that provides for, among other things, a
modified Weather Normalization Adjustment (WNA) which provides a
partial decoupling mechanism to stabilize margins and renewal of
the Rate Stabilization Clause (RSC) with provisions that
will reduce regulatory lag. The settlement also allowed the
recognition of $6.2 million of margin that had been
previously deferred as it was subject to refund.
|
|
|
|
In May 2006, the Mid-Tex Division filed a Statement of Intent
seeking incremental annual revenues of $60 million and
several rate design changes including WNA, revenue
stabilization, and recovery of the gas cost component of bad
debt. In July 2006, the Railroad Commission of Texas (RRC)
approved an interim WNA, effective October 1, 2006.
|
|
|
|
Our natural gas marketing segment net income increased
$8.8 million during the nine months ended June 30,
2006 compared with the nine months ended June 30, 2005. The
increase in natural gas marketing net income primarily reflects
our ability to capture higher margins in a volatile natural gas
market. These increases were partially offset by a
$28.2 million increase in unrealized losses reflected in
this segments gross profit, increased operating expenses
and increased interest charges resulting from increased
short-term borrowings to fund working capital needs.
|
|
|
|
Our pipeline and storage segment net income increased
$0.5 million during the nine months ended June 30,
2006 compared with the nine months ended June 30, 2005.
Increased gross profit margin resulting from higher
transportation and related services margins coupled with
increased throughput on our Atmos Pipeline-Texas system and
Atmos Pipeline & Storage, LLCs ability to capture
more favorable arbitrage spreads in its asset management
contracts were essentially offset by higher operating expenses.
|
|
|
|
Our
total-debt-to-capitalization
ratio at June 30, 2006 was 59.9 percent compared with
59.3 percent at September 30, 2005 reflecting the
impact of increased short-term debt borrowings to fund working
capital needs partially offset by current-year net income.
|
|
|
|
For the nine months ended June 30, 2006, we generated
$223.4 million in operating cash flow compared with
$387.4 million for the nine months ended June 30,
2005, reflecting the adverse impact of high natural gas costs on
our working capital.
|
|
|
|
Capital expenditures increased to $322.7 million in the
nine months ended June 30, 2006 from $226.9 million in
the prior-year period, primarily reflecting increased capital
spending for various pipeline expansion projects in our Atmos
Pipeline Texas Division, all of which were completed
during the third quarter of fiscal 2006.
|
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
32
we believe to be reasonable under the circumstances. On an
ongoing basis, we evaluate our estimates, including those
related to risk management and trading activities, allowance for
doubtful accounts, legal and environmental accruals, insurance
accruals, pension and postretirement obligations, deferred
income taxes and the valuation of goodwill, indefinite-lived
intangible assets and other long-lived assets. Actual results
may differ from such estimates.
Our critical accounting policies used in the preparation of our
consolidated financial statements are described in our Annual
Report on
Form 10-K
for the year ended September 30, 2005 and include the
following:
|
|
|
|
|
Regulation
|
|
|
|
Revenue Recognition
|
|
|
|
Allowance for Doubtful Accounts
|
|
|
|
Derivatives and Hedging Activities
|
|
|
|
Impairment Assessments
|
|
|
|
Pension and Other Postretirement Plans
|
Our critical accounting policies are reviewed by the Audit
Committee on a quarterly basis. There have been no significant
changes to these critical accounting policies during the nine
months ended June 30, 2006.
RESULTS
OF OPERATIONS
The following table presents our financial highlights for the
three-month and nine-month periods ended June 30, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Operating revenues
|
|
$
|
863,243
|
|
|
$
|
906,877
|
|
|
$
|
5,180,909
|
|
|
$
|
3,960,586
|
|
Gross profit
|
|
|
204,500
|
|
|
|
221,274
|
|
|
|
956,493
|
|
|
|
919,271
|
|
Operating expenses
|
|
|
199,697
|
|
|
|
181,806
|
|
|
|
621,160
|
|
|
|
578,948
|
|
Operating income
|
|
|
4,803
|
|
|
|
39,468
|
|
|
|
335,333
|
|
|
|
340,323
|
|
Miscellaneous income (expense)
|
|
|
963
|
|
|
|
1,524
|
|
|
|
(1,028
|
)
|
|
|
2,867
|
|
Interest charges
|
|
|
35,944
|
|
|
|
33,689
|
|
|
|
107,625
|
|
|
|
99,304
|
|
Income (loss) before income taxes
|
|
|
(30,178
|
)
|
|
|
7,303
|
|
|
|
226,680
|
|
|
|
243,886
|
|
Income tax expense (benefit)
|
|
|
(12,033
|
)
|
|
|
2,817
|
|
|
|
85,002
|
|
|
|
91,299
|
|
Net income (loss)
|
|
$
|
(18,145
|
)
|
|
$
|
4,486
|
|
|
$
|
141,678
|
|
|
$
|
152,587
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility sales volumes
MMcf
|
|
|
32,653
|
|
|
|
43,925
|
|
|
|
239,562
|
|
|
|
263,077
|
|
Utility transportation
volumes MMcf
|
|
|
29,630
|
|
|
|
28,753
|
|
|
|
91,384
|
|
|
|
88,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility
throughput MMcf
|
|
|
62,283
|
|
|
|
72,678
|
|
|
|
330,946
|
|
|
|
351,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing sales
volumes MMcf
|
|
|
66,472
|
|
|
|
52,739
|
|
|
|
207,418
|
|
|
|
179,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation
volumes MMcf
|
|
|
104,680
|
|
|
|
97,567
|
|
|
|
277,721
|
|
|
|
254,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating degree
days(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
119
|
|
|
|
167
|
|
|
|
2,507
|
|
|
|
2,580
|
|
Percent of normal
|
|
|
69
|
%
|
|
|
97
|
%
|
|
|
87
|
%
|
|
|
89
|
%
|
Consolidated utility average
transportation revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.48
|
|
|
$
|
0.53
|
|
|
$
|
0.53
|
|
Consolidated utility average cost
of gas per Mcf sold
|
|
$
|
7.11
|
|
|
$
|
7.43
|
|
|
$
|
10.39
|
|
|
$
|
7.20
|
|
|
|
|
(1) |
|
Adjusted for service areas that have weather-normalized
operations. |
33
The following table shows our operating income by segment for
the three-month and nine-month periods ended June 30, 2006
and 2005. The presentation of our utility operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
Operating
|
|
|
Heating Degree Days
|
|
|
Operating
|
|
|
Heating Degree Days
|
|
|
|
Income
|
|
|
Percent of
Normal(1)
|
|
|
Income
|
|
|
Percent of
Normal(1)
|
|
|
|
(In thousands, except degree day information)
|
|
|
Colorado-Kansas
|
|
$
|
163
|
|
|
|
87
|
%
|
|
$
|
2,451
|
|
|
|
105
|
%
|
Kentucky
|
|
|
(371
|
)
|
|
|
101
|
%
|
|
|
1,260
|
|
|
|
105
|
%
|
Louisiana
|
|
|
8,715
|
|
|
|
14
|
%
|
|
|
4,358
|
|
|
|
63
|
%
|
Mid-States
|
|
|
(2,734
|
)
|
|
|
85
|
%
|
|
|
1,600
|
|
|
|
99
|
%
|
Mid-Tex
|
|
|
(12,819
|
)
|
|
|
7
|
%
|
|
|
2,432
|
|
|
|
87
|
%
|
Mississippi
|
|
|
(1,265
|
)
|
|
|
115
|
%
|
|
|
(2,455
|
)
|
|
|
100
|
%
|
West Texas
|
|
|
4,383
|
|
|
|
98
|
%
|
|
|
4,992
|
|
|
|
100
|
%
|
Other
|
|
|
1,018
|
|
|
|
|
|
|
|
403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
(2,910
|
)
|
|
|
69
|
%
|
|
|
15,041
|
|
|
|
97
|
%
|
Natural gas marketing segment
|
|
|
(7,350
|
)
|
|
|
|
|
|
|
4,747
|
|
|
|
|
|
Pipeline and storage segment
|
|
|
14,919
|
|
|
|
|
|
|
|
19,356
|
|
|
|
|
|
Other nonutility segment and other
|
|
|
144
|
|
|
|
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
$
|
4,803
|
|
|
|
69
|
%
|
|
$
|
39,468
|
|
|
|
97
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
Operating
|
|
|
Heating Degree Days
|
|
|
Operating
|
|
|
Heating Degree Days
|
|
|
|
Income
|
|
|
Percent of
Normal(1)
|
|
|
Income
|
|
|
Percent of
Normal(1)
|
|
|
|
(In thousands, except degree day information)
|
|
|
Colorado-Kansas
|
|
$
|
23,423
|
|
|
|
98
|
%
|
|
$
|
26,934
|
|
|
|
99
|
%
|
Kentucky
|
|
|
14,876
|
|
|
|
100
|
%
|
|
|
17,863
|
|
|
|
98
|
%
|
Louisiana
|
|
|
25,202
|
|
|
|
78
|
%
|
|
|
26,941
|
|
|
|
78
|
%
|
Mid-States
|
|
|
36,459
|
|
|
|
95
|
%
|
|
|
37,443
|
|
|
|
94
|
%
|
Mid-Tex
|
|
|
67,423
|
|
|
|
72
|
%
|
|
|
82,002
|
|
|
|
80
|
%
|
Mississippi
|
|
|
25,480
|
|
|
|
102
|
%
|
|
|
24,661
|
|
|
|
96
|
%
|
West Texas
|
|
|
24,053
|
|
|
|
100
|
%
|
|
|
26,080
|
|
|
|
100
|
%
|
Other
|
|
|
4,187
|
|
|
|
|
|
|
|
1,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
221,103
|
|
|
|
87
|
%
|
|
|
243,326
|
|
|
|
89
|
%
|
Natural gas marketing segment
|
|
|
51,237
|
|
|
|
|
|
|
|
34,141
|
|
|
|
|
|
Pipeline and storage segment
|
|
|
62,557
|
|
|
|
|
|
|
|
61,959
|
|
|
|
|
|
Other nonutility segment and other
|
|
|
436
|
|
|
|
|
|
|
|
897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
$
|
335,333
|
|
|
|
87
|
%
|
|
$
|
340,323
|
|
|
|
89
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Adjusted for service areas that have weather-normalized
operations. |
34
Three
Months Ended June 30, 2006 compared with Three Months Ended
June 30, 2005
Utility
segment
Our utility segment has historically contributed 65 to
85 percent of our consolidated net income. The primary
factors that impact the results of our utility operations are
seasonal weather patterns, competitive factors in the energy
industry and economic conditions in our service areas. Natural
gas sales to residential, commercial and public authority
customers are affected by winter heating season requirements.
This generally results in higher operating revenues and net
income during the period from October through March of each year
and lower operating revenues and either lower net income or net
losses during the period from April through September of each
year. Accordingly, our second fiscal quarter has historically
been our most critical earnings quarter with an average of
approximately 67 percent of our consolidated net income
having been earned in the second quarter during the three most
recently completed fiscal years. Additionally, we typically
experience higher levels of accounts receivable, accounts
payable, gas stored underground and short-term debt balances
during the winter heating season due to the seasonal nature of
our revenues and the need to purchase and store gas to support
these operations. Utility sales to industrial customers are much
less weather sensitive. Utility sales to agricultural customers,
which typically use natural gas to power irrigation pumps during
the period from March through September, are primarily affected
by rainfall amounts and the price of natural gas.
Changes in the cost of gas impact revenue but do not directly
affect our gross profit from utility operations because the
fluctuations in gas prices are passed through to our customers.
Accordingly, we believe gross profit margin is a better
indicator of our financial performance than revenues. However,
higher gas costs may cause customers to conserve, or, in the
case of industrial customers, to use alternative energy sources.
Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt expense.
The effects of weather that is above or below normal are
partially offset through weather normalization adjustments, or
WNA, in certain of our service areas. WNA allows us to increase
the base rate portion of customers bills when weather is
warmer than normal and decrease the base rate when weather is
colder than normal. As of June 30, 2006, we had, or
received regulatory approvals for, WNA covering approximately
1.3 million customer meters in the following service areas
for the following periods.
|
|
|
|
|
Georgia
|
|
|
October May
|
|
Kansas
|
|
|
October May
|
|
Kentucky
|
|
|
November April
|
|
Louisiana(1)
|
|
|
December March
|
|
Mississippi
|
|
|
November April
|
|
Tennessee
|
|
|
November April
|
|
Amarillo, Texas
|
|
|
October May
|
|
West Texas
|
|
|
October May
|
|
Lubbock, Texas
|
|
|
October May
|
|
Virginia
|
|
|
January December
|
|
|
|
|
(1) |
|
Effective beginning for the
2006-2007
winter heating season. |
Our Mid-Tex Division did not have WNA as of June 30, 2006.
However, its operations benefited from a rate structure that
combined a monthly customer charge with a declining block rate
schedule to partially mitigate the impact of
warmer-than-normal
weather on revenue. The combination of the monthly customer
charge and the customer billing under the first block of the
declining block rate schedule provided for the recovery of most
of our fixed costs for such operations under most weather
conditions. However, this rate structure was not as beneficial
during periods where weather was significantly warmer than
normal.
In July 2006, the RRC approved an interim WNA, effective
October 1, 2006 for the Mid-Tex Division. The approved WNA
period will be October through May. After we filed our May 2006
Statement of Intent, the parties to the case reached an
agreement to implement WNA on both an interim and permanent
basis. The agreement provided that the interim WNA will use
30 years of weather history, while the permanent WNA will
allow the parties to
35
contest the appropriate period of weather data to use in
calculating normal weather. The permanent WNA will also be
modified or adjusted to conform to the rate design that the RRC
ultimately approves in the case. With the addition of this
interim settlement in the Mid-Tex Division and the LPSCs
May 2006 settlement to authorize our Louisiana Division to
implement WNA, we will have weather protection for over
90 percent of our residential and commercial meters for the
2006-2007
winter heating season.
Operating
income
Utility gross profit margin decreased $5.3 million to
$169.9 million for the three months ended June 30,
2006 from $175.2 million for the three months ended
June 30, 2005. Total throughput for our utility business
was 62.3 billion cubic feet (Bcf) during the current-year
period compared to 72.7 Bcf in the prior-year period.
The decrease in utility gross profit margin and throughput
primarily reflects continued
warmer-than-normal
weather, as adjusted for jurisdictions with weather-normalized
rates, primarily in our Mid-Tex and Louisiana divisions, where
we did not have weather-normalized rates during the third
quarter. Although the heating load is typically smaller during
the third fiscal quarter,
warmer-than-normal
weather can still adversely affect gross profit. Weather was
29 percent warmer than the prior-year quarter and
31 percent warmer than normal. The impact of warmer weather
resulted in a $16.2 million reduction in gross profit
margin compared with the prior-year quarter. Additionally, our
Louisiana division experienced a $1.3 million reduction in
gross profit margin during the current-year quarter due to the
impact of Hurricane Katrina compared with the prior-year
quarter. Finally, continued customer conservation contributed to
the decrease. These decreases were partially offset by a
$3.9 million increase arising from the Companys
fiscal 2005 and fiscal 2004 filings under Texass Gas
Reliability Infrastructure Program (GRIP) and the recognition of
$6.2 million that had been previously deferred in Louisiana
following the LPSCs ratification of our 2003 RSC in May
2006.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $172.8 million for the three months ended
June 30, 2006 from $160.2 million for the three months
ended June 30, 2005.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $10.4 million primarily due to
higher employee costs associated with increased headcount to
fill positions that were previously outsourced to a third party,
higher medical and dental claims and increased pension and
postretirement costs resulting from changes in the assumptions
used to determine our fiscal 2006 costs. Increased line locate
and facilities costs also contributed to the increase. These
increases were partially offset by lower third-party costs
associated with formerly outsourced administrative and meter
reading functions that were in-sourced during the first quarter
of fiscal 2006 and the reversal of a $2.0 million charge
for Hurricane Katrina losses that was originally recorded during
the first quarter of fiscal 2006. The accrual was reversed based
upon the improved outlook to fully recover our losses from
insurance recoveries and from increased rates that we are
implementing, subject to refund, in August 2006.
The provision for doubtful accounts decreased $1.9 million
to $2.1 million for the three months ended June 30,
2006. The decrease primarily was attributable to lower revenues
than the prior-year quarter coupled with solid customer account
collection efforts. In the utility segment, the average cost of
natural gas for the three months ended June 30, 2006 was
$7.11 per thousand cubic feet (Mcf), compared with
$7.43 per Mcf for the three months ended June 30, 2005.
As a result of the aforementioned factors, our utility segment
incurred an operating loss of $2.9 million for the three
months ended June 30, 2006 compared to operating income of
$15.0 million for the three months ended June 30, 2005.
Interest
charges
Interest charges allocated to the utility segment for the three
months ended June 30, 2006 increased to $30.9 million
from $28.5 million for the three months ended June 30,
2005. The increase was attributable to higher average
outstanding short-term debt balances to fund natural gas
purchases at significantly higher prices coupled with a
200 basis point increase in the interest rate on our
$300 million unsecured floating rate Senior Notes due 2007
36
due to an increase in the three-month LIBOR rate. These
increases were partially offset by $1.2 million of interest
savings arising from the early payoff of $72.5 million of
our First Mortgage Bonds in June 2005.
Natural
gas marketing segment
Our natural gas marketing segment 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 derivative products. 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 for services we deliver.
To optimize the storage and transportation capacity we own or
control, we 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. Additionally, we engage 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 contracts
at advantageous prices to lock in a gross profit margin. Through
the use of transportation and storage services and derivative
contracts, we are able to capture gross profit margin through
the arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
Operating
income
Gross profit margin for our natural gas marketing segment
consists primarily of storage activities, which are comprised of
the optimization of our managed proprietary and third party
storage and transportation assets and marketing activities,
which represent the utilization of proprietary and
customer-owned transportation and storage assets to provide the
various services our customers request.
Our natural gas marketing segments gross profit margin for
the three months ended June 30, 2006 and 2005 is summarized
as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except physical position)
|
|
|
Storage Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
$
|
7,717
|
|
|
$
|
(1,777
|
)
|
Unrealized margin
|
|
|
(21,873
|
)
|
|
|
961
|
|
|
|
|
|
|
|
|
|
|
Total Storage Activities
|
|
|
(14,156
|
)
|
|
|
(816
|
)
|
Marketing Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
|
12,691
|
|
|
|
12,347
|
|
Unrealized margin
|
|
|
579
|
|
|
|
(1,136
|
)
|
|
|
|
|
|
|
|
|
|
Total Marketing Activities
|
|
|
13,270
|
|
|
|
11,211
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
(886
|
)
|
|
$
|
10,395
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
19.0
|
|
|
|
14.1
|
|
|
|
|
|
|
|
|
|
|
Our natural gas marketing segments gross profit margin was
a loss of $0.9 million for the three months ended
June 30, 2006 compared to gross profit of
$10.4 million for the three months ended June 30,
2005. Gross profit margin from our natural gas marketing segment
for the three months ended June 30, 2006 included an
unrealized loss of $21.3 million compared with an
unrealized loss of $0.2 million in the prior-year period.
Natural gas
37
marketing sales volumes were 79.9 Bcf during the three
months ended June 30, 2006 compared with 62.8 Bcf for the
prior-year period. Excluding intersegment sales volumes, natural
gas marketing sales volumes were 66.5 Bcf during the
current-year period compared with 52.7 Bcf in the
prior-year period. The increase in consolidated natural gas
marketing sales volumes primarily was attributable to
successfully executed marketing strategies into new market areas.
Our storage activities incurred a loss of $14.2 million for
the three months ended June 30, 2006 compared to a loss of
$0.8 million for the three months ended June 30, 2005.
Our marketing activities generated $13.3 million for the
three months ended June 30, 2006 compared with
$11.2 million for the three months ended June 30,
2005. Higher unrealized losses primarily were attributable to
unfavorable movements in market prices used to value our
physical storage. These unrealized losses were offset by higher
realized storage activities due to captured spread arbitrage
opportunities that were realized during the current-year quarter.
The $11.3 million decrease in our natural gas marketing
gross profit margin was primarily due to unfavorable movements
during the three months ended June 30, 2006 in the forward
natural gas prices used to value the financial hedges designated
against our physical inventory and our fixed-price forward
contracts. These results in our storage operations were
magnified by a 4.9 Bcf increase in our net physical
position at June 30, 2006 compared to the prior-year
quarter. We have elected to exclude the forward/spot
differential from our hedge effectiveness assessment. Subsequent
to the hurricanes, which occurred in the fall of 2005, the
forward/spot differential has been volatile and may continue to
cause material volatility in our unrealized margin. However, the
economic gross profit we have captured in the original
transactions will remain essentially unchanged.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $6.5 million for the three months ended
June 30, 2006 from $5.6 million for the three months
ended June 30, 2005. The increase in operating expense
primarily was attributable to an increase in personnel costs due
to increased headcount and an increase in regulatory compliance
costs.
The decrease in gross profit margin, combined with higher
operating expenses, resulted in a decrease in our natural gas
marketing segment operating income to a loss of
$7.4 million for the three months ended June 30, 2006
compared with operating income of $4.7 million for the
three months ended June 30, 2005.
Interest
charges
Interest charges allocated to the natural gas marketing segment
for the three months ended June 30, 2006 increased to
$1.7 million from $1.0 million for the three months
ended June 30, 2005. The increase was attributable to
higher average outstanding debt balances to fund natural gas
purchases at significantly higher prices.
Pipeline
and storage segment
Our pipeline and storage segment consists of the regulated
pipeline and storage operations of the Atmos
Pipeline Texas Division and the nonregulated
pipeline and storage operations of Atmos Pipeline and Storage,
LLC. 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 in the
pipeline industry including parking arrangements, blending and
sales of inventory on hand. These operations represent one of
the largest intrastate pipeline operations in Texas with a heavy
concentration in the established natural gas-producing areas of
central, northern and eastern Texas, extending into or near the
major producing areas of the Texas Gulf Coast and the Delaware
and Val Verde Basins of West Texas. Nine basins located in Texas
are believed to contain a substantial portion of the
nations remaining onshore natural gas reserves. This
pipeline system provides access to all of these basins.
Atmos Pipeline and Storage, LLC, owns or has an interest in
underground storage fields in Kentucky and Louisiana. We also
use these storage facilities to reduce the need to contract for
additional pipeline capacity to meet customer demand during peak
periods.
Similar to our utility segment, our pipeline and storage segment
is impacted by seasonal weather patterns, competitive factors in
the energy industry and economic conditions in our service
areas. Natural gas transportation
38
requirements are affected by the winter heating season
requirements of our customers. This generally results in higher
operating revenues and net income during the period from October
through March of each year and lower operating revenues and
either lower net income or net losses during the period from
April through September of each year. Further, as the Atmos
Pipeline Texas Division operations provide all of
the natural gas for our Mid-Tex Division, the results of this
segment are highly dependent upon the natural gas requirements
of this division.
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.
Operating
income
Pipeline and storage gross profit increased to
$35.5 million for the three months ended June 30, 2006
from $35.2 million for the three months ended June 30,
2005. Total pipeline transportation volumes were 133.3 Bcf
during the three months ended June 30, 2006 compared with
128.5 Bcf for the prior-year quarter. Excluding
intersegment transportation volumes, total pipeline
transportation volumes were 104.7 Bcf during the current
year quarter compared with 97.6 Bcf in the prior-year
quarter. The increase was primarily attributable to higher
transportation and related services margins in our Atmos
Pipeline-Texas Division partially offset by higher unrealized
losses recorded by Atmos Pipeline & Storage, LLC.
Operating expenses increased to $20.6 million for the three
months ended June 30, 2006 from $15.8 million for the
three months ended June 30, 2005 due to higher employee
benefit costs associated with an increase in headcount, higher
medical and dental claims and increased pension and
postretirement costs resulting from changes in the assumptions
used to determine our fiscal 2006 costs. Higher pipeline
integrity and facilities costs also contributed to the increased
level of operating expenses.
As a result of the aforementioned factors, our pipeline and
storage segment operating income for the three months ended
June 30, 2006 decreased to $14.9 million from
$19.4 million for the three months ended June 30, 2005.
Other
nonutility segment
Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services, LLC (AES), and Atmos Power
Systems, Inc. Through AES, we provide natural gas management
services to our utility operations, other than the Mid-Tex
Division. These services include aggregating and purchasing gas
supply, arranging transportation and storage logistics and
ultimately delivering the gas to our utility service areas at
competitive prices in exchange for revenues that are equal to
the costs incurred to provide those services. Through Atmos
Power Systems, Inc., we have constructed electric peaking
power-generating plants and associated facilities and have
entered into agreements to lease these plants.
Operating income for this segment primarily reflects the leasing
income associated with two sales-type lease transactions
completed in 2001 and 2002 and was essentially unchanged for the
three months ended June 30, 2006 compared with the
prior-year quarter.
Nine
Months Ended June 30, 2006 compared with Nine Months Ended
June 30, 2005
Utility
segment
Operating
income
Utility gross profit increased $10.2 million to
$765.8 million for the nine months ended June 30, 2006
from $755.6 million for the nine months ended June 30,
2005. Total throughput for our utility business was
330.9 billion cubic feet (Bcf) during the current-year
period compared to 351.7 Bcf in the prior-year period.
The increase in utility gross profit, despite lower throughput,
primarily reflects higher franchise fees and state gross
receipts taxes, which are paid by utility customers and have no
permanent effect on net income. Additionally, margins increased
$8.3 million due to rate increases received from the
Companys fiscal 2005 and fiscal 2004 GRIP filings and the
recognition of $6.2 million that had been previously
deferred in Louisiana following the LPSCs ratification of
our agreement in May 2006. These increases were partially offset
by an approximate $4.8 million
39
decrease in the Louisiana Division due to the impact of
Hurricane Katrina compared with the prior-year period. For the
nine months ended June 30, 2006, weather was
13 percent warmer than normal, as adjusted for
jurisdictions with weather-normalized operations and three
percent warmer than the prior-year period. In the Mid-Tex and
Louisiana Divisions, which did not have weather-normalized rates
during the
2005-2006
winter heating season, weather was 28 percent and
22 percent warmer than normal. The impact of the warmer
weather resulted in a $22.1 million reduction in gross
profit margin compared with the prior-year period.
Operating expenses increased to $544.7 million for the nine
months ended June 30, 2006 from $512.3 million for the
nine months ended June 30, 2005. The increase reflects a
$17.1 million increase in taxes, primarily related to
franchise fees and state gross receipts taxes, both of which are
calculated as a percentage of revenue, and are paid by our
customers as a component of their monthly bills. Although these
amounts are included as a component of revenue in accordance
with our tariffs, timing differences between when these amounts
are billed to our customers and when we recognize the associated
expense may affect net income favorably or unfavorably on a
temporary basis. However, there is no permanent effect on net
income.
Operation and maintenance expense, excluding the provision for
bad debt, increased $8.4 million primarily due to higher
employee costs associated with increased headcount to fill
positions that were previously outsourced to a third party,
higher medical and dental claims and increased pension and
postretirement costs resulting from changes in the assumptions
used to determine our fiscal 2006 costs. Increased line locate
and facilities costs also contributed to the overall increase.
These increases were partially offset by a reduction in
third-party costs for outsourced administrative and meter
reading functions that were in-sourced during fiscal 2006.
Operation and maintenance expense for the nine months ended
June 30, 2006 was also favorably impacted by the absence of
$2.1 million of United Cities merger and integration cost
amortization, as these costs were fully amortized by December
2004.
The provision for doubtful accounts increased $4.2 million
to $17.5 million for the nine months ended June 30,
2006, compared with $13.3 million in the prior-year period.
The increase was primarily attributable to increased collection
risk associated with higher natural gas prices. In the utility
segment, the average cost of natural gas for the nine months
ended June 30, 2006 was $10.39 per Mcf, compared with
$7.20 per Mcf for the nine months ended June 30, 2005.
Additionally, during the first quarter of fiscal 2006, the
Mississippi Public Service Commission, in connection with the
modification of our rate design described below under Recent
Ratemaking Activity, decided to allow $2.8 million of
deferred costs, which it had originally disallowed in its
September 2004 decision. This ruling decreased our depreciation
expense during the nine months ended June 30, 2006. This
decrease was offset by increased depreciation expense associated
with the placement of various capital projects into service
during the fiscal year.
As a result of the aforementioned factors, our utility segment
operating income for the nine months ended June 30, 2006
decreased to $221.1 million from $243.3 million for
the nine months ended June 30, 2005.
Interest
charges
Interest charges allocated to the utility segment for the nine
months ended June 30, 2006 increased to $92.8 million
from $83.8 million for the nine months ended June 30,
2005. The increase was attributable to higher average
outstanding short-term debt balances to fund natural gas
purchases at significantly higher prices coupled with a
200 basis point increase in the interest rate on our
$300 million unsecured floating rate Senior Notes due 2007
due to an increase in the three-month LIBOR rate. These
increases were partially offset by $3.6 million of interest
savings arising from the early payoff of $72.5 million of
our First Mortgage Bonds in June 2005.
Miscellaneous
income
Miscellaneous income for the nine months ended June 30,
2006 remained essentially unchanged at $6.0 million
compared to $6.1 million for the nine months ended
June 30, 2005. However, during the fiscal 2006 second
quarter, we recorded a $3.3 million charge associated with
an adverse ruling in Tennessee related to the calculation of a
performance-based rate mechanism associated with gas purchases.
This charge was offset by increased interest
40
income associated with intercompany borrowings to our natural
gas marketing segment to fund its working capital needs.
Natural
gas marketing segment
Operating
income
Our natural gas marketing segments gross profit margin for
the nine months ended June 30, 2006 and 2005 is summarized
as follows:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except physical position)
|
|
|
Storage Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
$
|
44,600
|
|
|
$
|
15,482
|
|
Unrealized margin
|
|
|
(42,924
|
)
|
|
|
(7,065
|
)
|
|
|
|
|
|
|
|
|
|
Total Storage Activities
|
|
|
1,676
|
|
|
|
8,417
|
|
Marketing Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
|
63,263
|
|
|
|
43,182
|
|
Unrealized margin
|
|
|
4,471
|
|
|
|
(3,200
|
)
|
|
|
|
|
|
|
|
|
|
Total Marketing Activities
|
|
|
67,734
|
|
|
|
39,982
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
69,410
|
|
|
$
|
48,399
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
19.0
|
|
|
|
14.1
|
|
|
|
|
|
|
|
|
|
|
Our natural gas marketing segments gross profit margin was
$69.4 million for the nine months ended June 30, 2006
compared to gross profit of $48.4 million for the nine
months ended June 30, 2005. Gross profit margin from our
natural gas marketing segment for the nine months ended
June 30, 2006 included an unrealized loss of
$38.5 million compared with an unrealized loss of
$10.3 million in the prior-year period. Natural gas
marketing sales volumes were 250.1 Bcf during the nine
months ended June 30, 2006 compared with 203.8 Bcf for
the prior-year period. Excluding intersegment sales volumes,
natural gas marketing sales volumes were 207.4 Bcf during
the current-year period compared with 179.7 Bcf in the
prior-year period. The increase in consolidated natural gas
marketing sales volumes was primarily due to focusing our
marketing efforts on higher margin opportunities partially
offset by
warmer-than-normal
weather across our market areas.
Our storage activities generated $1.7 million in gross
profit margin for the nine months ended June 30, 2006
compared to $8.4 million for the nine months ended
June 30, 2005. Increased realized margins in our storage
operations were primarily due to our ability to capture more
favorable arbitrage spreads that arose from increased market
volatility. These increases were offset by an increase in the
unrealized loss associated with these operations due to an
unfavorable movement during the nine months ended June 30,
2006 in the forward natural gas prices used to value the
financial hedges designated against our physical inventory and
our fixed-price forward contracts. These results were magnified
by a 4.9 Bcf increase in our net physical position at
June 30, 2006 compared to the prior-year period. As noted
above, we have elected to exclude this forward/spot differential
from our hedge effectiveness assessment. We continually seek
opportunities to increase the amount of our storage capacity. To
the extent we obtain and utilize new capacity and experience
price volatility, the amount of our unrealized storage
contribution could increase in future periods.
Our marketing activities generated $67.7 million for the
nine months ended June 30, 2006 compared with
$40.0 million for the nine months ended June 30, 2005.
This increase reflects increased realized margins coupled with a
favorable unrealized margin variance compared with the
prior-year period. The increase in our realized marketing
operations was primarily attributable to successfully capturing
increased margins in certain market areas that experienced
higher market volatility. The favorable unrealized margin
variance was primarily due to favorable
41
movement during the nine months ended June 30, 2006 in the
forward natural gas prices associated with financial derivatives
used in these activities.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $18.2 million for the nine months ended
June 30, 2006 from $14.3 million for the nine months
ended June 30, 2005. The increase in operating expense
primarily was attributable to an increase in personnel costs due
to increased headcount and an increase in regulatory compliance
costs.
The improved gross profit margin partially offset by higher
operating expenses resulted in an increase in our natural gas
marketing segment operating income to $51.2 million for the
nine months ended June 30, 2006 compared with operating
income of $34.1 million for the nine months ended
June 30, 2005.
Interest
charges
Interest charges allocated to the natural gas marketing segment
for the nine months ended June 30, 2006 increased to
$6.6 million from $2.0 million for the nine months
ended June 30, 2005. The increase was attributable to
higher average outstanding debt balances to fund natural gas
purchases at significantly higher prices.
Pipeline
and storage segment
Operating
income
Pipeline and storage gross profit increased to
$120.5 million for the nine months ended June 30, 2006
from $113.8 million for the nine months ended June 30,
2005. Total pipeline transportation volumes were 431.2 Bcf
during the nine months ended June 30, 2006 compared with
417.4 Bcf for the prior-year period. Excluding intersegment
transportation volumes, total pipeline transportation volumes
were 277.7 Bcf during the current year period compared with
254.5 Bcf in the prior-year period. The increase in gross
profit was primarily attributable to higher transportation and
related services margins coupled with increased throughput on
our Atmos Pipeline-Texas system and Atmos Pipeline &
Storage, LLCs ability to capture more favorable arbitrage
spreads in its asset management contracts. These increases were
partially offset by the absence of inventory sales of
$3.0 million realized in the prior-year period.
Operating expenses increased to $57.9 million for the nine
months ended June 30, 2006 from $51.8 million for the
nine months ended June 30, 2005 due to higher employee
benefit costs associated with the increase in headcount,
increased pension and postretirement costs resulting from
changes in the assumptions used to determine our fiscal 2006
costs and higher facilities costs.
As a result of the aforementioned factors, our pipeline and
storage segment operating income for the nine months ended
June 30, 2006 increased to $62.6 million from
$62.0 million for the nine months ended June 30, 2005.
Other
nonutility segment
Operating income for this segment primarily reflects the leasing
income associated with two sales-type lease transactions
completed in 2001 and 2002 and was essentially unchanged for the
nine months ended June 30, 2006 compared with the
prior-year period.
Liquidity
and Capital Resources
Our working capital and liquidity for capital expenditures and
other cash needs are provided from internally generated funds,
borrowings under our credit facilities and commercial paper
program. We believe that these sources of funds will provide the
necessary working capital and liquidity for capital expenditures
and other cash needs for the remainder of fiscal 2006.
Additionally, from time to time, we raise funds from the public
debt and equity capital markets to fund our liquidity needs.
42
Capitalization
The following table presents our capitalization as of
June 30, 2006 and September 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2006
|
|
|
September 30, 2005
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
297,087
|
|
|
|
7.2
|
%
|
|
$
|
144,809
|
|
|
|
3.7
|
%
|
Long-term debt
|
|
|
2,184,083
|
|
|
|
52.7
|
%
|
|
|
2,186,368
|
|
|
|
55.6
|
%
|
Shareholders equity
|
|
|
1,664,556
|
|
|
|
40.1
|
%
|
|
|
1,602,422
|
|
|
|
40.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization, including
short-term debt
|
|
$
|
4,145,726
|
|
|
|
100.0
|
%
|
|
$
|
3,933,599
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt as a percentage of total capitalization, including
short-term debt, was 59.9 percent at June 30, 2006,
and 59.3 percent at September 30, 2005. The increase
in the debt to capitalization ratio was primarily attributable
to an increase in our short-term debt borrowings to fund our
working capital needs partially offset by current-year net
income. Our ratio of total debt to capitalization is typically
greater during the winter heating season as we make additional
short-term borrowings to fund natural gas purchases and meet our
working capital requirements. Within two to four years, we
intend to reduce our capitalization ratio to a target range of
50 to 55 percent through cash flow generated from
operations, continued issuance of new common stock under our
Direct Stock Purchase Plan and Retirement Savings Plan, access
to the equity capital markets and reduced annual maintenance and
capital expenditures.
Cash
Flows
Our internally generated funds may change in the future due to a
number of factors, some of which we cannot control. These
include regulatory changes, prices for our products and
services, demand for such products and services, margin
requirements resulting from significant changes in commodity
prices, operational risks and other factors.
Cash
flows from operating activities
Period-over-period
changes in our operating cash flows primarily are attributable
to changes in net income, working capital changes, particularly
within our utility segment resulting from the impact of weather,
the price of natural gas and the timing of customer collections,
payments for natural gas purchases and deferred gas cost
recoveries.
For the nine months ended June 30, 2006, we generated
operating cash flow of $223.4 million from operating
activities compared with $387.4 million for the nine months
ended June 30, 2005. Period over period, our operating cash
flow was adversely impacted by significantly higher natural gas
prices, which have increased the levels of accounts payable and
undercollected deferred gas costs recorded on our balance sheet
as of June 30, 2006. However, we are beginning to see the
adverse impact of this situation decline somewhat as declines in
accounts receivable and natural gas inventories improved
operating cash flow by $79.7 million compared with the
prior-year period. Additionally, favorable movements in the
market indices used to value our natural gas marketing segment
risk management assets and liabilities reduced the amount that
we were required to deposit in a margin account and therefore
favorably affected operating cash flow by $45.4 million.
However, these improvements in cash flow were offset by an
unfavorable timing of payments for accounts payable and other
accrued liabilities ($251.4 million) and unfavorable timing
differences between when we purchase our natural gas and the
period in which we can include this cost in our gas rates
($54.3 million). Finally, other working capital and other
changes increased operating cash flow by $16.6 million.
Cash
flows from investing activities
During the last three years, a substantial portion of our cash
resources was used to fund acquisitions, our ongoing
construction program and improvements to information systems.
Our ongoing construction program enables us to provide natural
gas distribution services to our existing customer base, to
expand our natural gas distribution services into new markets,
to enhance the integrity of our pipelines and, more recently, to
expand our intrastate pipeline network. In executing our current
rate strategy, we are directing discretionary capital spending
to
43
jurisdictions that permit us to earn a return on our investment
timely. Currently, our Mid-Tex, Louisiana, Mississippi and West
Texas utility divisions and our Atmos Pipeline Texas
Division have rate designs that provide the opportunity to
include in their rate base approved capital costs on a periodic
basis without having to file a rate case.
Capital expenditures for fiscal 2006 are expected to range from
$400 million to $415 million. For the nine months
ended June 30, 2006, we incurred $322.7 million for
capital expenditures compared with $226.9 million for the
nine months ended June 30, 2005. The increase in capital
expenditures primarily reflects increased spending associated
with our Dallas/Fort Worth Metroplex North Side Loop
project and other pipeline expansion projects in our Atmos
Pipeline Texas Division, which were completed during
the fiscal 2006 third quarter. Increased capital spending in our
Mid-Tex Division for various projects contributed to the
increase in our capital expenditures.
Cash
flows from financing activities
For the nine months ended June 30, 2006, our financing
activities provided $90.8 million in cash compared with
$1.6 billion provided in the prior-year period. Our
significant financing activities for the nine months ended
June 30, 2006 and 2005 are summarized as follows. The
adoption of SFAS 123(R) did not materially affect our cash
flows from financing activities.
|
|
|
|
|
In October 2004, we sold 16.1 million shares of common
stock, including the underwriters exercise of their
overallotment option of 2.1 million shares, under a new
shelf registration statement declared effective in September
2004, generating net proceeds of $382 million.
Additionally, we issued $1.39 billion of senior unsecured
debt under our shelf registration statement. The net proceeds
from these issuances, combined with the net proceeds from our
July 2004 offering were used to finance the acquisition of our
Mid-Tex and Atmos Pipeline Texas divisions and
settle Treasury lock agreements, into which we entered to fix
the Treasury yield component of the interest cost of financing
associated with $875 million of the $1.39 billion
long-term debt we issued in October 2004 to fund the acquisition.
|
|
|
|
During the nine months ended June 30, 2006 we increased our
borrowings under our credit facilities by $152.3 million.
All amounts borrowed under our credit facilities were repaid
during the nine months ended June 30, 2005. The increase
reflects borrowings to fund natural gas purchases and other
working capital needs.
|
|
|
|
We repaid $2.6 million of long-term debt during the nine
months ended June 30, 2006 compared with
$102.8 million during the nine months ended June 30,
2005. The prior-year payments reflect the repayment of
$72.5 million on our First Mortgage Bonds and a
$25.0 million make-whole premium in accordance with the
terms of the agreements.
|
|
|
|
During the nine months ended June 30, 2006 we paid
$76.6 million in cash dividends compared with dividend
payments of $74 million for the nine months ended
June 30, 2005. The increase in dividends paid over the
prior-year period reflects the increase in our dividend rate
from $0.930 per share during the nine months ended
June 30, 2005 to $0.945 per share during the nine months
ended June 30, 2006 combined with new share issuances under
our various plans.
|
44
|
|
|
|
|
During the nine months ended June 30, 2006 we issued
0.7 million shares of common stock which generated net
proceeds of $17.7 million. In addition, we granted
0.3 million shares of common stock under our Long-Term
Incentive Plan. The following table summarizes the issuances for
the nine months ended June 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
Retirement Savings Plan
|
|
|
344,573
|
|
|
|
338,520
|
|
Direct Stock Purchase Plan
|
|
|
302,501
|
|
|
|
353,512
|
|
Outside Directors
Stock-for-Fee
Plan
|
|
|
1,865
|
|
|
|
1,769
|
|
Long-Term Incentive Plan
|
|
|
349,509
|
|
|
|
655,684
|
|
Long-Term Stock Plan for
Mid-States Division
|
|
|
300
|
|
|
|
|
|
Public Offering
|
|
|
|
|
|
|
16,100,000
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
998,748
|
|
|
|
17,449,485
|
|
|
|
|
|
|
|
|
|
|
In August 2004, we filed a registration statement with the
Securities and Exchange Commission (SEC) to issue, from time to
time, up to $2.2 billion in new common stock
and/or debt,
which became effective on September 15, 2004. In October
2004, we sold 16.1 million common shares and issued
$1.4 billion in unsecured senior notes to partially finance
the acquisition of our Mid-Tex and Atmos Pipeline
Texas divisions. After these issuances, we have approximately
$401.5 million of availability remaining under the
registration statement.
We maintain both committed and uncommitted credit facilities.
Borrowings under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas charged
by suppliers and the increased gas supplies required to meet
customers needs during periods of cold weather. Our cash
needs for working capital have increased substantially as a
result of the significant increase in the price of natural gas.
In October 2005, our $600 million
364-day
committed credit facility expired and was replaced with a new
$600 million three-year revolving credit facility that
became effective October 18, 2005. In addition, on
November 10, 2005, we entered into a new $300 million
364-day
revolving credit facility with substantially the same terms as
our $600 million credit facility.
On November 28, 2005, AEM amended its uncommitted demand
working capital credit facility to increase the amount of credit
available from $250 million to a maximum of
$580 million. On March 31, 2006, AEM amended and
extended this uncommitted demand working capital credit facility
to March 31, 2007. At June 30, 2006, there were no
borrowings outstanding under this facility.
On April 1, 2006, our $18 million committed unsecured
credit facility was renewed for one year with no material
changes to its terms and pricing. At June 30, 2006, there
was $15.2 million outstanding under this facility.
As of June 30, 2006, the amount available to us under our
credit facilities, net of outstanding letters of credit, was
$770.6 million. We believe these credit facilities,
combined with our operating cash flows will be sufficient to
fund our increased working capital needs. These facilities are
described in further detail in Note 4 to the condensed
consolidated financial statements.
45
Our credit ratings directly affect our ability to obtain
short-term and long-term financing, in addition to the cost of
such financing. In determining our credit ratings, the rating
agencies consider a number of quantitative factors, including
debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and
pension liabilities and funding status. In addition, the rating
agencies consider qualitative factors such as consistency of our
earnings over time, the quality of our management and business
strategy, the risks associated with our utility and nonutility
businesses and the regulatory structures that govern our rates
in the states where we operate.
Our debt is rated by three rating agencies: Standard &
Poors Corporation (S&P), Moodys Investors
Service (Moodys) and Fitch Ratings, Ltd. (Fitch). Our
current debt ratings are all considered investment grade and are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
Moodys
|
|
Fitch
|
|
Unsecured senior long-term debt
|
|
|
BBB
|
|
|
|
Baa3
|
|
|
|
BBB+
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-3
|
|
|
|
F-2
|
|
Currently, with respect to our unsecured senior long-term debt,
S&P, Moodys and Fitch maintain their stable outlook.
None of our ratings are currently under review.
A credit rating is not a recommendation to buy, sell or hold
securities. The highest investment grade credit rating for
S&P is AAA, Moodys is Aaa and Fitch is AAA. The lowest
investment grade credit rating for S&P is BBB-, Moodys
is Baa3 and Fitch is BBB-. Our credit ratings may be revised or
withdrawn at any time by the rating agencies, and each rating
should be evaluated independent of any other rating. There can
be no assurance that a rating will remain in effect for any
given period of time or that a rating will not be lowered, or
withdrawn entirely, by a rating agency if, in its judgment,
circumstances so warrant.
We were in compliance with all of our debt covenants as of
June 30, 2006. Our debt covenants are described in
Note 4 to the condensed consolidated financial statements.
Contractual
Obligations and Commercial Commitments
Significant commercial commitments are described in Note 8.
There were no significant changes in our contractual obligations
and commercial commitments during the nine months ended
June 30, 2006.
Risk
Management Activities
We conduct risk management activities through both our utility
and natural gas marketing segments. In our utility segment, we
use a combination of storage, fixed physical contracts and fixed
financial contracts to reduce our exposure to unusually large
winter-period gas price increases. In our natural gas marketing
segment, we manage our exposure to the risk of natural gas price
changes and lock in our gross profit margin through a
combination of storage and financial derivatives, including
futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. To the extent our inventory cost and actual
sales and actual purchases do not correlate with the changes in
the market indices we use in our hedges, we could experience
ineffectiveness or the hedges may no longer meet the accounting
requirements for hedge accounting, resulting in the derivatives
being treated as mark to market instruments through earnings.
46
We record our derivatives as a component of risk management
assets and liabilities, which are classified as current or
noncurrent based upon the anticipated settlement date of the
underlying derivative. Substantially all of our derivative
financial instruments are valued using external market quotes
and indices. The following tables show the components of the
change in the fair value of our utility and natural gas
marketing commodity derivative contracts for the three and nine
months ended June 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
|
June 30, 2006
|
|
|
June 30, 2005
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
Natural Gas
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Utility
|
|
|
Marketing
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at
beginning of period
|
|
$
|
12,352
|
|
|
$
|
(3,414
|
)
|
|
$
|
24,367
|
|
|
$
|
(5,896
|
)
|
Contracts realized/settled
|
|
|
(1,099
|
)
|
|
|
(20,923
|
)
|
|
|
163
|
|
|
|
(7,843
|
)
|
Fair value of new contracts
|
|
|
(2,577
|
)
|
|
|
|
|
|
|
(155
|
)
|
|
|
|
|
Other changes in value
|
|
|
(1,045
|
)
|
|
|
(5,460
|
)
|
|
|
1,081
|
|
|
|
5,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of
period
|
|
$
|
7,631
|
|
|
$
|
(29,797
|
)
|
|
$
|
25,456
|
|
|
$
|
(8,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30, 2006
|
|
|
June 30, 2005
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
Natural Gas
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Utility
|
|
|
Marketing
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at
beginning of period
|
|
$
|
93,310
|
|
|
$
|
(61,898
|
)
|
|
$
|
(8,612
|
)
|
|
$
|
13,018
|
|
Contracts realized/settled
|
|
|
25,799
|
|
|
|
2,099
|
|
|
|
(45,234
|
)
|
|
|
(24,377
|
)
|
Fair value of new contracts
|
|
|
(7,337
|
)
|
|
|
|
|
|
|
(3,009
|
)
|
|
|
|
|
Other changes in value
|
|
|
(104,141
|
)
|
|
|
30,002
|
|
|
|
82,311
|
|
|
|
3,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of
period
|
|
$
|
7,631
|
|
|
$
|
(29,797
|
)
|
|
$
|
25,456
|
|
|
$
|
(8,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of our utility and natural gas marketing
derivative contracts at June 30, 2006, is segregated below
by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at June 30, 2006
|
|
|
|
Maturity in Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Greater
|
|
|
Total Fair
|
|
Source of Fair Value
|
|
Less than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
Than 5
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Prices actively quoted
|
|
$
|
(15,365
|
)
|
|
$
|
(8,715
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(24,080
|
)
|
Prices provided by other external
sources
|
|
|
2,519
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
2,469
|
|
Prices based on models and other
valuation methods
|
|
|
(285
|
)
|
|
|
(270
|
)
|
|
|
|
|
|
|
|
|
|
|
(555
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(13,131
|
)
|
|
$
|
(9,035
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(22,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
Storage
and Hedging Outlook
AEM participates in transactions in which it seeks to find and
profit from pricing differences that occur over time. AEM
purchases physical natural gas and then sells financial
contracts at advantageous prices to lock in a gross profit
margin. AEM is able to capture gross profit margin through the
arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
Natural gas inventory is marked to market at the end of each
month with changes in fair value recognized as unrealized gains
and losses in the period of change. Effective October 1,
2005, the Company changed its mark to market measurement from
Inside FERC to Gas Daily to better reflect the prices of our
physical commodity. This change had no material impact to the
Company on the date of adoption. Derivatives associated with our
natural gas inventory, which are designated as fair value
hedges, 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 changes in the
difference between the indices used to mark to market our
physical inventory (Gas Daily) and the related fair-value hedge
(NYMEX) is reported as a component of revenue and can result in
volatility in our reported net income. Over time, gains and
losses on the sale of storage gas inventory will be offset by
gains and losses on the fair-value hedges; therefore, the
economic gross profit AEM captured in the original transaction
remains essentially unchanged.
AEM continually manages its positions to enhance the future
economic profit it captured in the original transaction.
Therefore, AEM may change its scheduled injection and withdrawal
plans from one time period to another based on market conditions
or adjust the amount of storage capacity it holds on a
discretionary basis in an effort to achieve this objective. AEM
monitors the impacts of these profit optimization efforts by
estimating the economic gross profit that it captured through
the purchase and sale of physical natural gas and the associated
financial derivatives. The economic gross profit, combined with
the effect of unrealized gains or losses recognized in the
financial statements in prior periods, provides a measure of the
gross profit that could occur in future periods if AEMs
optimization efforts are fully successful. The following table
presents, by quarter during fiscal 2006, AEMs economic
gross profit and its potential gross profit.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated Net
|
|
|
|
|
|
|
Net Physical
|
|
|
Economic
|
|
|
Unrealized
|
|
|
Potential
|
|
Period Ending
|
|
Position (Bcf)
|
|
|
Gross Profit
|
|
|
Losses
|
|
|
Gross Profit
|
|
|
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
September 30, 2005
|
|
|
6.9
|
|
|
$
|
13.1
|
|
|
$
|
(14.8
|
)
|
|
$
|
27.9
|
|
December 31, 2005
|
|
|
12.8
|
|
|
$
|
7.1
|
|
|
$
|
(38.6
|
)
|
|
$
|
45.7
|
|
March 31, 2006
|
|
|
23.6
|
|
|
$
|
30.8
|
|
|
$
|
(35.8
|
)
|
|
$
|
66.6
|
|
June 30, 2006
|
|
|
19.0
|
|
|
$
|
28.4
|
|
|
$
|
(57.7
|
)
|
|
$
|
86.1
|
|
As of June 30, 2006, based upon AEMs derivatives
position and inventory withdrawal schedule, the economic gross
profit was $28.4 million. In addition, $57.7 million
of net unrealized losses were recorded in the financial
statements as of June 30, 2006. Therefore, the potential
gross profit was $86.1 million.
The economic gross profit is based upon planned injection and
withdrawal schedules, and the realization of the economic gross
profit is contingent upon the execution of this plan, weather
and other execution factors. Since AEM actively manages and
optimizes its portfolio to enhance the future profitability of
its storage position, it may change its scheduled injection and
withdrawal plans from one time period to another based on market
conditions. Therefore, we cannot ensure that the economic gross
profit or the potential gross profit calculated as of
June 30, 2006 will be fully realized in the future or in
what time period. Further, if we experience operational or other
issues which limit our ability to optimally manage our stored
gas positions, permanent impacts on earnings could result.
Pension
and Postretirement Benefits Obligations
For the nine months ended June 30, 2006 and 2005 our total
net periodic pension and other benefits cost was
$37.4 million and $27.3 million. All of these costs
are recoverable through our gas utility rates; however, a
portion of these costs is capitalized into our utility rate
base. The remaining costs are recorded as a component of
operation and maintenance expense.
48
The increase in total net periodic pension and other benefits
cost during the current-year period compared with the prior-year
period primarily reflects changes in assumptions we made during
our annual pension plan valuation completed June 30, 2005.
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. In the
period leading up to our June 30, 2005 measurement date,
these interest rates were declining, which resulted in a
125 basis point reduction in our discount rate to
5.0 percent. This reduction has the effect of increasing
the present value of our plan liabilities and associated
expenses. Additionally, we reduced the expected return on our
pension plan assets by 25 basis points to 8.5 percent,
which also has the effect of increasing our pension and
postretirement benefit cost.
During the nine months ended June 30, 2006, we contributed
$2.8 million to the Atmos Energy Corporation Retirement
Plan for Mississippi Valley Gas Union Employees. The current
year contribution achieved a desired level of funding by
satisfying the minimum funding requirements while maximizing the
tax deductible contribution for this plan for plan year 2005. We
anticipate making no additional contributions to our pension
plans for the remainder of fiscal 2006. However, we contributed
$7.9 million to our other postretirement plans, and we
expect to contribute a total of approximately $12 million
to these plans during fiscal 2006.
49
OPERATING
STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for
our utility, natural gas marketing, pipeline and storage and
other nonutility segments for the three and nine-month periods
ended June 30, 2006 and 2005.
Utility
Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
METERS IN SERVICE, end of
period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,889,470
|
|
|
|
2,866,950
|
|
|
|
2,889,470
|
|
|
|
2,866,950
|
|
Commercial
|
|
|
276,492
|
|
|
|
275,878
|
|
|
|
276,492
|
|
|
|
275,878
|
|
Industrial
|
|
|
3,056
|
|
|
|
3,090
|
|
|
|
3,056
|
|
|
|
3,090
|
|
Agricultural
|
|
|
8,924
|
|
|
|
9,822
|
|
|
|
8,924
|
|
|
|
9,822
|
|
Public-authority and other
|
|
|
8,210
|
|
|
|
8,172
|
|
|
|
8,210
|
|
|
|
8,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,186,152
|
|
|
|
3,163,912
|
|
|
|
3,186,152
|
|
|
|
3,163,912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE
BALANCE Bcf
|
|
|
46.7
|
|
|
|
40.0
|
|
|
|
46.7
|
|
|
|
40.0
|
|
HEATING DEGREE
DAYS(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
119
|
|
|
|
167
|
|
|
|
2,507
|
|
|
|
2,580
|
|
Percent of normal
|
|
|
69
|
%
|
|
|
97
|
%
|
|
|
87
|
%
|
|
|
89
|
%
|
UTILITY SALES
VOLUMES
MMcf(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
13,176
|
|
|
|
20,528
|
|
|
|
132,754
|
|
|
|
149,774
|
|
Commercial
|
|
|
11,719
|
|
|
|
15,148
|
|
|
|
74,691
|
|
|
|
80,059
|
|
Industrial
|
|
|
4,161
|
|
|
|
5,995
|
|
|
|
21,224
|
|
|
|
23,886
|
|
Agricultural
|
|
|
2,759
|
|
|
|
787
|
|
|
|
3,115
|
|
|
|
913
|
|
Public authority and other
|
|
|
838
|
|
|
|
1,467
|
|
|
|
7,778
|
|
|
|
8,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
32,653
|
|
|
|
43,925
|
|
|
|
239,562
|
|
|
|
263,077
|
|
Utility transportation volumes
|
|
|
30,735
|
|
|
|
30,420
|
|
|
|
95,329
|
|
|
|
94,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility throughput
|
|
|
63,388
|
|
|
|
74,345
|
|
|
|
334,891
|
|
|
|
357,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILITY OPERATING REVENUES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
208,164
|
|
|
$
|
271,153
|
|
|
$
|
1,875,636
|
|
|
$
|
1,575,186
|
|
Commercial
|
|
|
112,100
|
|
|
|
141,465
|
|
|
|
944,591
|
|
|
|
731,762
|
|
Industrial
|
|
|
31,417
|
|
|
|
46,932
|
|
|
|
237,274
|
|
|
|
182,854
|
|
Agricultural
|
|
|
18,940
|
|
|
|
5,830
|
|
|
|
22,576
|
|
|
|
7,092
|
|
Public-authority and other
|
|
|
8,094
|
|
|
|
13,160
|
|
|
|
95,305
|
|
|
|
75,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility gas sales revenues
|
|
|
378,715
|
|
|
|
478,540
|
|
|
|
3,175,382
|
|
|
|
2,572,226
|
|
Transportation revenues
|
|
|
13,662
|
|
|
|
14,095
|
|
|
|
48,721
|
|
|
|
47,839
|
|
Other gas revenues
|
|
|
9,667
|
|
|
|
9,100
|
|
|
|
30,571
|
|
|
|
30,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility operating revenues
|
|
$
|
402,044
|
|
|
$
|
501,735
|
|
|
$
|
3,254,674
|
|
|
$
|
2,650,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility average transportation
revenue per Mcf
|
|
$
|
0.44
|
|
|
$
|
0.46
|
|
|
$
|
0.51
|
|
|
$
|
0.51
|
|
Utility average cost of gas per
Mcf sold
|
|
$
|
7.11
|
|
|
$
|
7.43
|
|
|
$
|
10.39
|
|
|
$
|
7.20
|
|
See footnotes following these tables.
50
Natural
Gas Marketing, Pipeline and Storage and Other Nonutility
Operations Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
CUSTOMERS, end of
period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
679
|
|
|
|
659
|
|
|
|
679
|
|
|
|
659
|
|
Municipal
|
|
|
73
|
|
|
|
79
|
|
|
|
73
|
|
|
|
79
|
|
Other
|
|
|
444
|
|
|
|
431
|
|
|
|
444
|
|
|
|
431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,196
|
|
|
|
1,169
|
|
|
|
1,196
|
|
|
|
1,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE
BALANCE Bcf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing
|
|
|
20.1
|
|
|
|
15.2
|
|
|
|
20.1
|
|
|
|
15.2
|
|
Pipeline and storage
|
|
|
2.5
|
|
|
|
2.8
|
|
|
|
2.5
|
|
|
|
2.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22.6
|
|
|
|
18.0
|
|
|
|
22.6
|
|
|
|
18.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NATURAL GAS MARKETING SALES
VOLUMES
MMcf(2)
|
|
|
79,850
|
|
|
|
62,798
|
|
|
|
250,056
|
|
|
|
203,770
|
|
PIPELINE TRANSPORTATION
VOLUMES MMcf(2)
|
|
|
133,306
|
|
|
|
128,453
|
|
|
|
431,185
|
|
|
|
417,370
|
|
OPERATING REVENUES
(000s)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing
|
|
$
|
562,447
|
|
|
$
|
466,835
|
|
|
$
|
2,482,921
|
|
|
$
|
1,473,527
|
|
Pipeline and storage
|
|
|
35,862
|
|
|
|
33,449
|
|
|
|
121,057
|
|
|
|
122,685
|
|
Other nonutility
|
|
|
1,413
|
|
|
|
1,421
|
|
|
|
4,500
|
|
|
|
4,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
599,722
|
|
|
$
|
501,705
|
|
|
$
|
2,608,478
|
|
|
$
|
1,600,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes to preceding tables:
|
|
|
(1) |
|
A heating degree day is equivalent to each degree that the
average of the high and the low temperatures for a day is below
65 degrees. The colder the climate, the greater the number of
heating degree days. Heating degree days are used in the natural
gas industry to measure the relative coldness of weather and to
compare relative temperatures between one geographic area and
another. Normal degree days are based on
30-year
average National Weather Service data for selected locations.
Degree day information for the three and nine-month periods
ended June 30, 2006 and 2005 is adjusted for the Kentucky
Division, the Mississippi Division and certain service areas
included within the Colorado-Kansas Division, the Mid-States
Division and the West Texas Division, which have
weather-normalized operations. |
|
(2) |
|
Sales volumes and revenues reflect segment operations, including
intercompany sales and transportation amounts. |
Recent
Ratemaking Activity
Our ratemaking activities during fiscal 2006 are described in
the following discussion. The amounts described below represent
the gross revenues that were requested or received in the rate
filing, which may not necessarily reflect the increase in
operating income obtained, as certain operating costs may have
increased as a result of a commissions final ruling.
Atmos Pipeline-Texas. In April 2006,
Atmos Pipeline-Texas made a filing under Texas Gas
Reliability Infrastructure Program (GRIP) to include in rate
base approximately $22.1 million of pipeline capital
expenditures incurred during calendar year 2005, which should
result in additional annual revenues of approximately
$3.4 million. Atmos Pipeline-Texas subsequently agreed to
reduce the capital investment in this filing by approximately
$0.5 million. It is anticipated that this reduction will
not materially affect the annual revenues. The Railroad
Commission of Texas (RRC) approved this filing in July 2006 and
these new charges will be included in the monthly customer
charge beginning in August 2006.
51
In September 2005, Atmos Pipeline-Texas made a filing under
Texas GRIP to include in rate base approximately
$10.6 million of pipeline capital expenditures incurred
during calendar year 2004 which should result in additional
annual revenues of approximately $1.9 million. The RRC
approved this filing in December 2005 and these new charges were
included in the monthly customer charge beginning in January
2006.
Atmos Energy Colorado-Kansas
Division. In December 2005, Atmos filed its
second annual ad valorem tax surcharge for $1.6 million.
The surcharge is designed to collect Kansas property taxes in
excess of the amount included in Atmos most recent general
rate case. We began to bill this surcharge in January 2006.
Atmos Energy Kentucky Division. In
February 2005, the Attorney General of the State of Kentucky
filed a complaint with the Kentucky Public Service Commission
(KPSC) alleging that our rates were producing revenues in excess
of reasonable levels. We answered the complaint and filed a
Motion to Dismiss with the KPSC. On February 2, 2006, the
KPSC issued an Order denying our Motion to Dismiss but stated
that the Attorney General had not met their burden of proof
concerning their complaint. On March 3, 2006, the KPSC set
a procedural schedule for the case. The Attorney General is
currently conducting discovery. A hearing should be scheduled
for early 2007. We believe that the Attorney General will not be
able to demonstrate that our present rates are in excess of
reasonable levels.
In February 2006, the KPSC approved the Companys request
to continue its Performance Based Ratemaking (PBR) mechanism for
an additional five year period. The PBR establishes
predetermined gas cost benchmarks and provides incentives to the
Company for purchasing gas supply below those benchmark costs.
This mechanism has produced more than $20 million in gas
cost savings since its inception in July 1998, with the Kentucky
Division retaining over $8 million during that period.
Atmos has filed for KPSC approval of a proposed supply
agreement, which resulted from a request for proposal to
prospective suppliers.
Atmos Energy Louisiana Division. During
the second quarter of fiscal 2005, the Louisiana Division
implemented a rate increase in its LGS service area. This
increase resulted from our Rate Stabilization Clause (RSC)
filing in 2004 and was subject to refund, pending the final
resolution of that filing. As the rate increase was subject to
refund, we did not recognize this rate increase in our results
of operations during fiscal 2005 or 2006.
In September 2005, the Louisiana Public Service Commission
(LPSC) consolidated several then-existing dockets. These dockets
included a separate proceeding for the renewal of the RSC for
each of the LGS and TransLa Gas service areas; resolution
of the outstanding 2003 RSC filing for the LGS service area; and
our request for approval of a decoupling mechanism to stabilize
margins in both the LGS and TransLa service areas.
A proposed settlement was filed with the LPSC in May 2006. The
settlement provided for, among other things, a modified WNA
which provides for partial decoupling, renewal of the RSC for
both the LGS and TransLa service areas with provisions that
will reduce regulatory lag and a refund to customers of
approximately $0.4 million for the LGS service areas that
had been previously deferred.
On May 25, 2006, the LPSC voted to approve the settlement.
The first RSC filing to result will be in August 2006, based on
a test year ended December 31, 2005, for the LGS service
area. The effective date for any rate adjustment resulting from
that filing will be August 12, 2006. The first filing for
the TransLa service area will be made by December 31,
2006, for the test period ending September 30, 2006, with
an effective rate adjustment of April 1, 2007. WNA for both
service areas will be in effect for an initial three-year period
beginning with the winter of
2006-2007.
In the third quarter of fiscal 2006, $6.2 million in
deferred revenue associated with the 2003 RSC rate adjustment
was recognized.
Atmos Energy Mid-States
Division. During the third quarter of fiscal
2005, Atmos filed a rate case in its Georgia service area
seeking a rate increase of $4 million. In December 2005,
the Georgia Public Service Commission (GPSC) approved a
$0.4 million increase. In January 2006, we filed an appeal
of the GPSCs decision in the Superior Court of Fulton
County. Oral arguments are scheduled for September 7, 2006
before the Fulton County Superior Court.
On April 7, 2006, Atmos filed a rate case in its Missouri
service area seeking a rate increase of $3.4 million. The
Company is proposing to consolidate the rates for its Missouri
properties into three sets of regional rates and consolidate the
current purchased gas adjustment (PGA) into one statewide PGA.
The Company is also proposing a
52
WNA mechanism. An evidentiary hearing is scheduled to begin on
November 27, 2006, with an order expected to be issued
February 22, 2007.
In March 2006, we received notification from the Tennessee
Regulatory Authority (TRA) that it disagreed with the way we
calculated amounts under its performance-based rate mechanism,
which resulted in a $3.3 million charge during the second
quarter of fiscal 2006. We believe the original calculations
were correct, and we will appeal the TRAs decision.
In November 2005, we received a notice from the TRA that it was
opening an investigation into allegations by the Consumer
Advocate and Protection Division of the Tennessee Attorney
Generals Office that we are overcharging customers in
parts of Tennessee by approximately $10 million per year.
We have responded to numerous data requests from the TRA Staff.
On April 24, 2006, the TRA Staff filed a Report and
Recommendation in which it recommended that the TRA convene a
contested case procedure for the purpose of establishing a fair
and reasonable return. The TRA convened to consider the
Staffs recommendation on May 15, 2006 and set a
procedural schedule. All parties filed direct testimony on
July 17, 2006, with rebuttal testimony due August 18,
2006. A hearing is scheduled for August 29, 2006. We
believe that the Consumer Advocate and Protection Division will
not be able to demonstrate that our present rates are in excess
of reasonable levels.
Atmos Energy Mid-Tex Division. In May
2006, the Mid-Tex Division filed a Statement of Intent seeking
incremental annual revenues of $60 million and several rate
design changes including WNA, revenue stabilization, and
recovery of the gas cost component of bad debt. The Statement of
Intent consolidated show cause resolutions that had
been filed in approximately 80 cities served by the Mid-Tex
Division, including the City of Dallas, which requires the
Mid-Tex Division to demonstrate that existing distribution rates
are just and reasonable.
In July 2006, the Mid-Tex Division and the RRC agreed to
implement WNA on both an interim and permanent basis, effective
October 1, 2006. The agreement provided that the interim
WNA will use 30 years of weather history, while the
permanent WNA will allow the parties to contest the appropriate
period of weather data to use in calculating normal weather. The
permanent WNA will also be modified or adjusted to conform to
the rate design that the RRC ultimately approves in the case,
which is anticipated no later than the first quarter of calendar
2007. Any rate increase will be effective prospectively from the
date of the final order; however, any rate decrease will be
effective from May 31, 2006.
In March 2006, the Mid-Tex Division made a GRIP filing to
include in rate base approximately $63.6 million of
distribution capital expenditures incurred during calendar year
2005 which should result in additional annual revenues of
approximately $12.1 million. The Mid-Tex Division
subsequently agreed to reduce the capital investment in this
filing by approximately $1.5 million. It is anticipated
that this reduction will not materially affect the annual
revenues. The implementation date of this filing has been
delayed until September 1, 2006 because of delays related
to municipal appeals.
In September 2005, the Mid-Tex Division made a GRIP filing to
include in rate base approximately $29.4 million of
distribution capital expenditures incurred during calendar year
2004, which should result in additional annual revenues of
approximately $6.7 million. The RRC approved this filing in
January 2006, and these new charges were included in the monthly
customer charge beginning in February 2006.
On September 1, 2005, the Mid-Tex Division filed its annual
gas cost reconciliation with the RRC. The filing reflects
approximately $14 million in refunds of amounts that were
overcollected from customers between July 1, 2004 and
June 30, 2005. The Mid-Tex Division refunded substantially
all of the overcollected amounts to customers between December
2005 and March 2006 to help offset higher gas costs for
residential, commercial and industrial customers.
In September 2004, the Mid-Tex Division filed its
36-Month Gas
Contract Review with the RRC. This proceeding involves a
prudency review of gas purchases totaling $2.2 billion made
by the Mid-Tex Division from November 1, 2000 through
October 31, 2003. A hearing on this matter was held before
the RRC in June 2005. A Proposal for Decision has been issued
recommending a disallowance. Exceptions and Replies to
Exceptions have been filed. The case is currently scheduled for
presentation to the RRC on August 8, 2006, but a decision
is not expected until August 22, 2006. Additionally, all
parties are currently conducting settlement negotiations.
53
Atmos Energy Mississippi
Division. Through the first quarter of fiscal
2005, the Mississippi Public Service Commission (MPSC) required
that we file for rate adjustments every six months. Rate filings
were made in May and November of each year and the rate
adjustments typically became effective in the following July and
January.
Effective October 1, 2005, our rate design was modified to
substitute the original agreed-upon benchmark with a sharing
mechanism to allow the sharing of cost savings above an allowed
return on equity level. Further, we moved from a semi-annual
filing process to an annual filing process. Additionally, our
WNA period now begins on November 1 instead of
November 15, and will end on April 30 instead of
May 15. Also, we now have a fixed monthly customer base
charge which makes a portion of our earnings less susceptible to
variations in usage. We will make our first annual filing under
this new structure in September 2006.
In September 2004, the MPSC originally disallowed certain
deferred costs totaling $2.8 million. In connection with
the modification of our rate design described above, the MPSC
decided to allow these costs, and we included these costs in our
rates in October 2005.
On June 30, 2006, the MPSC approved a pilot program whereby
Trans Louisiana Gas Pipeline (TLGP) will provide asset
management services to the Mississippi Division. The asset
management pilot allows TLGP to market certain off-peak gas
supply assets, such as company-owned or leased storage and
pipeline capacity, on a recallable basis. In exchange for this
TLGP will share net positive benefits of the asset management
program with Mississippi ratepayers. The pilot program runs from
June 1, 2006 to April 30, 2007 and may be extended by
the MPSC upon application by Atmos.
Atmos Energy West Texas Division. In
September 2005, Atmos made a GRIP filing to include in rate base
approximately $22.6 million of distribution capital costs
incurred during calendar year 2004, which should result in
additional annual revenues of approximately $3.8 million.
The filings were approved for all jurisdictions except for the
inside city limits customers in the West Texas service area, who
rejected the filings. We filed an appeal of such matters with
the RRC, which appeal was granted by the RRC in March 2006. New
charges for the approved filings were included in the monthly
customer charge beginning May 1, 2006. Atmos expects to
make its 2005 GRIP filing for the West Texas Division in
September 2006.
In January 2006, the Lubbock, Texas City Council passed a
resolution requiring Atmos to submit copies of all documentation
necessary for the city to review the rates of Atmos West
Texas Division to ensure they are just and reasonable. The
requested information was provided to the city on
February 28, 2006. We believe that we will be able to
ultimately demonstrate to the City of Lubbock that our rates are
just and reasonable.
In May 2006, Atmos began receiving show cause
ordinances from several of the cities in the West Texas
Division. The ordinances request a filing to be made no later
than September 15, 2006. We believe that we will be able to
ultimately demonstrate to the West Texas cities that our rates
are just and reasonable.
RECENT
ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial
position, results of operations and cash flows are described in
Note 2 to the condensed consolidated financial statements.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
We are exposed to risks associated with commodity prices and
interest rates. Commodity price risk is the potential loss that
we may incur as a result of changes in the fair value of a
particular instrument or commodity. Interest-rate risk results
from our portfolio of debt and equity instruments that we issue
to provide financing and liquidity for our business activities.
We conduct risk management activities through both our utility
and natural gas marketing segments. In our utility segment, we
use a combination of storage, fixed physical contracts and fixed
financial contracts to protect us and our customers against
unusually large winter period gas price increases. In our
natural gas marketing segment, we manage our exposure to the
risk of natural gas price changes and lock in our gross profit
margin through a combination of storage and financial
derivatives including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. Our risk management activities and related
accounting treatment are
54
described in further detail in Note 3 to the condensed
consolidated financial statements. Additionally, our earnings
are affected by changes in short-term interest rates as a result
of our issuance of short-term commercial paper, the issuance of
floating rate debt and our other short-term borrowings.
Commodity
Price Risk
Utility
segment
We purchase natural gas for our utility operations.
Substantially all of the cost of gas purchased for utility
operations is recovered from our customers through purchased gas
adjustment mechanisms. However, our utility operations have
commodity price risk exposure to fluctuations in spot natural
gas prices related to purchases for sales to our nonregulated
energy services customers at fixed prices.
For our utility segment, we use a sensitivity analysis to
estimate commodity price risk. For purposes of this analysis, we
estimate commodity price risk by applying a hypothetical
10 percent increase in the portion of our gas cost related
to fixed-price nonregulated sales. Based on projected
nonregulated gas sales for the remainder of fiscal 2006, a
hypothetical 10 percent increase in fixed prices, based
upon the June 30, 2006 three-month market strip, would
increase our purchased gas cost by approximately
$1.8 million for the remainder of fiscal 2006.
Natural
gas marketing and pipeline and storage segments
Our natural gas marketing segment is also exposed to risks
associated with changes in the market price of natural gas. For
our natural gas marketing segment, we use a sensitivity analysis
to estimate commodity price risk. For purposes of this analysis,
we estimate commodity price risk by applying a $0.50 change in
the forward NYMEX price to our net open position (including
existing storage and related financial contracts) at the end of
each period. Because AEH had no net open positions (including
existing storage and related financial contracts) at
June 30, 2006, a $0.50 change in the forward NYMEX price
would have no impact on our consolidated net income.
However, changes in the difference between the indices used to
mark to market our net physical inventory (Gas Daily) and the
related fair-value hedge (NYMEX) can result in volatility in our
reported net income; but, over time, gains and losses on the
sale of storage gas inventory will be offset by gains and losses
on the fair-value hedges. Based upon our net physical position
at June 30, 2006 and assuming our hedges would still
qualify as highly effective, a $0.50 change in the difference
between the Gas Daily and NYMEX indices could impact our
reported net income by approximately $6.5 million.
Interest
Rate Risk
Our earnings are exposed to changes in short-term interest rates
associated with our short-term commercial paper program and
other short-term borrowings. We use a sensitivity analysis to
estimate our short-term interest rate risk. For purposes of this
analysis, we estimate our short-term interest rate risk as the
difference between our actual interest expense for the period
and estimated interest expense for the period assuming a
hypothetical average one percent increase in the interest rates
associated with our short-term borrowings. Had interest rates
associated with our short-term borrowings increased by an
average of one percent, our interest expense would have
increased by approximately $3.7 million during the nine
months ended June 30, 2006.
We also assess market risk for our fixed and floating rate
long-term obligations. We estimate market risk for our long-term
obligations as the potential increase in fair value resulting
from a hypothetical one percent decrease in interest rates
associated with these debt instruments. Fair value is estimated
using a discounted cash flow analysis. Assuming this one percent
hypothetical decrease, the fair value of our long-term
obligations would have increased by approximately
$128.6 million.
As of June 30, 2006 we were not engaged in other activities
that would cause exposure to the risk of material earnings or
cash flow loss due to changes in interest rates or market
commodity prices.
55
|
|
Item 4.
|
Controls
and Procedures
|
As indicated in the certifications in Exhibit 31 of this
report, the Companys Chief Executive Officer and Chief
Financial Officer have evaluated the Companys disclosure
controls and procedures as of June 30, 2006. Based on that
evaluation, these officers have concluded that the
Companys disclosure controls and procedures are effective
in ensuring that material information required to be disclosed
in this quarterly report is accumulated and communicated to our
management, including our principal executive and principal
financial officers, as appropriate, to allow timely decisions
regarding required disclosure. In addition, there were no
changes during the Companys last fiscal quarter that
materially affected, or are reasonably likely to materially
affect, the Companys internal control over financial
reporting.
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
During the nine months ended June 30, 2006, there were no
material changes in the status of the litigation and
environmental-related matters that were disclosed in
Note 13 to our annual report on
Form 10-K
for the year ended September 30, 2005. 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 net cash flows.
A list of exhibits required by Item 601 of
Regulation S-K
and filed as part of this report is set forth in the
Exhibits Index, which immediately precedes such exhibits.
56
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Atmos Energy Corporation
(Registrant)
John P. Reddy
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: August 9, 2006
57
EXHIBITS INDEX
Item 6(a)
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
Description
|
|
Page Number
|
|
|
12
|
|
|
Computation of ratio of earnings
to fixed charges
|
|
|
|
|
|
|
|
|
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15
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Letter regarding unaudited interim
financial information
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31
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Rule 13a-14(a)/15d-14(a)
Certifications
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32
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Section 1350 Certifications*
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* |
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These certifications, which were made pursuant to 18 U.S.C.
Section 1350 by the Companys Chief Executive Officer
and Chief Financial Officer, furnished as Exhibit 32 to
this Quarterly Report on
Form 10-Q,
will not be deemed to be filed with the Commission or
incorporated by reference into any filing by the Company under
the Securities Act of 1933 or the Securities Exchange Act of
1934, except to the extent that the Company specifically
incorporates such certifications by reference. |