e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
|
|
|
(Mark One)
|
|
|
þ
|
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the
quarterly period ended June 30,
2009
|
or
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the transition period
from to
|
Commission File Number 1-10042
Atmos Energy
Corporation
(Exact name of registrant as
specified in its charter)
|
|
|
Texas and Virginia
(State or other jurisdiction
of
incorporation or organization)
|
|
75-1743247
(IRS employer
identification no.)
|
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal
executive offices)
|
|
75240
(Zip
code)
|
(972) 934-9227
(Registrants telephone
number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its Web site, if any, every
Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files).* Yes o No o
* The registrant has not yet been phased into the interactive
data requirements.
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
|
|
|
|
Large
Accelerated
Filer þ
|
Accelerated
Filer o
|
Non-Accelerated
Filer o
|
Smaller
Reporting
Company o
|
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act) Yes o No þ
Number of shares outstanding of each of the issuers
classes of common stock, as of July 31, 2009.
|
|
|
Class
|
|
Shares Outstanding
|
|
No Par Value
|
|
92,272,478
|
TABLE OF CONTENTS
GLOSSARY
OF KEY TERMS
|
|
|
AEC
|
|
Atmos Energy Corporation
|
AEH
|
|
Atmos Energy Holdings, Inc.
|
AEM
|
|
Atmos Energy Marketing, LLC
|
AOCI
|
|
Accumulated other comprehensive income
|
APS
|
|
Atmos Pipeline and Storage, LLC
|
Bcf
|
|
Billion cubic feet
|
FASB
|
|
Financial Accounting Standards Board
|
Fitch
|
|
Fitch Ratings, Ltd.
|
FSP
|
|
FASB Staff Position
|
GRIP
|
|
Gas Reliability Infrastructure Program
|
LPSC
|
|
Louisiana Public Service Commission
|
Mcf
|
|
Thousand cubic feet
|
MMcf
|
|
Million cubic feet
|
MPSC
|
|
Mississippi Public Service Commission
|
Moodys
|
|
Moodys Investors Services, Inc.
|
NYMEX
|
|
New York Mercantile Exchange, Inc.
|
PPA
|
|
Pension Protection Act of 2006
|
RRC
|
|
Railroad Commission of Texas
|
RRM
|
|
Rate Review Mechanism
|
S&P
|
|
Standard & Poors Corporation
|
SEC
|
|
United States Securities and Exchange Commission
|
SFAS
|
|
Statement of Financial Accounting Standards
|
WNA
|
|
Weather Normalization Adjustment
|
1
PART I.
FINANCIAL INFORMATION
|
|
Item 1.
|
Financial
Statements
|
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(In thousands, except
|
|
|
|
share data)
|
|
|
ASSETS
|
Property, plant and equipment
|
|
$
|
5,963,098
|
|
|
$
|
5,730,156
|
|
Less accumulated depreciation and amortization
|
|
|
1,623,734
|
|
|
|
1,593,297
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
4,339,364
|
|
|
|
4,136,859
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
125,735
|
|
|
|
46,717
|
|
Accounts receivable, net
|
|
|
241,582
|
|
|
|
477,151
|
|
Gas stored underground
|
|
|
317,275
|
|
|
|
576,617
|
|
Other current assets
|
|
|
111,420
|
|
|
|
184,619
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
796,012
|
|
|
|
1,285,104
|
|
Goodwill and intangible assets
|
|
|
738,615
|
|
|
|
739,086
|
|
Deferred charges and other assets
|
|
|
222,039
|
|
|
|
225,650
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,096,030
|
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
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, 2009 92,234,134 shares;
|
|
|
|
|
|
|
|
|
September 30, 2008 90,814,683 shares
|
|
$
|
461
|
|
|
$
|
454
|
|
Additional paid-in capital
|
|
|
1,779,184
|
|
|
|
1,744,384
|
|
Retained earnings
|
|
|
451,856
|
|
|
|
343,601
|
|
Accumulated other comprehensive loss
|
|
|
(39,981
|
)
|
|
|
(35,947
|
)
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
2,191,520
|
|
|
|
2,052,492
|
|
Long-term debt
|
|
|
2,169,395
|
|
|
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,360,915
|
|
|
|
4,172,284
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
221,968
|
|
|
|
395,388
|
|
Other current liabilities
|
|
|
422,200
|
|
|
|
460,372
|
|
Short-term debt
|
|
|
|
|
|
|
350,542
|
|
Current maturities of long-term debt
|
|
|
131
|
|
|
|
785
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
644,299
|
|
|
|
1,207,087
|
|
Deferred income taxes
|
|
|
510,901
|
|
|
|
441,302
|
|
Regulatory cost of removal obligation
|
|
|
322,529
|
|
|
|
298,645
|
|
Deferred credits and other liabilities
|
|
|
257,386
|
|
|
|
267,381
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,096,030
|
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
2
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
386,985
|
|
|
$
|
676,639
|
|
Regulated transmission and storage segment
|
|
|
49,345
|
|
|
|
46,286
|
|
Natural gas marketing segment
|
|
|
453,504
|
|
|
|
1,189,722
|
|
Pipeline, storage and other segment
|
|
|
8,226
|
|
|
|
3,880
|
|
Intersegment eliminations
|
|
|
(117,285
|
)
|
|
|
(277,382
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
780,775
|
|
|
|
1,639,145
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
195,303
|
|
|
|
476,711
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
438,482
|
|
|
|
1,192,353
|
|
Pipeline, storage and other segment
|
|
|
4,212
|
|
|
|
706
|
|
Intersegment eliminations
|
|
|
(116,862
|
)
|
|
|
(276,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
521,135
|
|
|
|
1,392,923
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
259,640
|
|
|
|
246,222
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
110,895
|
|
|
|
117,822
|
|
Depreciation and amortization
|
|
|
54,181
|
|
|
|
50,356
|
|
Taxes, other than income
|
|
|
47,577
|
|
|
|
57,335
|
|
Asset impairments
|
|
|
3,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
215,957
|
|
|
|
225,513
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
43,683
|
|
|
|
20,709
|
|
Miscellaneous income
|
|
|
1,219
|
|
|
|
1,600
|
|
Interest charges
|
|
|
41,511
|
|
|
|
33,470
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
3,391
|
|
|
|
(11,161
|
)
|
Income tax expense (benefit)
|
|
|
1,427
|
|
|
|
(4,573
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per share
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
|
Diluted net income (loss) per share
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.330
|
|
|
$
|
0.325
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
91,338
|
|
|
|
89,648
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
92,002
|
|
|
|
89,648
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
3
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except
|
|
|
|
per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
2,673,373
|
|
|
$
|
3,126,672
|
|
Regulated transmission and storage segment
|
|
|
163,261
|
|
|
|
142,772
|
|
Natural gas marketing segment
|
|
|
1,949,657
|
|
|
|
3,159,092
|
|
Pipeline, storage and other segment
|
|
|
36,946
|
|
|
|
20,629
|
|
Intersegment eliminations
|
|
|
(504,724
|
)
|
|
|
(668,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
4,318,513
|
|
|
|
5,780,640
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
|
1,816,227
|
|
|
|
2,296,020
|
|
Regulated transmission and storage segment
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
1,881,068
|
|
|
|
3,099,428
|
|
Pipeline, storage and other segment
|
|
|
9,771
|
|
|
|
1,773
|
|
Intersegment eliminations
|
|
|
(503,456
|
)
|
|
|
(666,835
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
3,203,610
|
|
|
|
4,730,386
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,114,903
|
|
|
|
1,050,254
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
365,312
|
|
|
|
359,064
|
|
Depreciation and amortization
|
|
|
160,757
|
|
|
|
147,659
|
|
Taxes, other than income
|
|
|
150,028
|
|
|
|
153,170
|
|
Asset impairments
|
|
|
5,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
681,479
|
|
|
|
659,893
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
433,424
|
|
|
|
390,361
|
|
Miscellaneous income (expense)
|
|
|
(647
|
)
|
|
|
2,974
|
|
Interest charges
|
|
|
116,035
|
|
|
|
103,803
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
316,742
|
|
|
|
289,532
|
|
Income tax expense
|
|
|
109,812
|
|
|
|
110,783
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
2.28
|
|
|
$
|
2.00
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
2.26
|
|
|
$
|
1.99
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.990
|
|
|
$
|
0.975
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
90,940
|
|
|
|
89,281
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
91,590
|
|
|
|
89,937
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
4
ATMOS
ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
Charged to depreciation and amortization
|
|
|
160,757
|
|
|
|
147,659
|
|
Charged to other accounts
|
|
|
60
|
|
|
|
106
|
|
Deferred income taxes
|
|
|
62,658
|
|
|
|
77,864
|
|
Other
|
|
|
23,009
|
|
|
|
12,767
|
|
Net assets/liabilities from risk management activities
|
|
|
53,711
|
|
|
|
(78,524
|
)
|
Net change in operating assets and liabilities
|
|
|
317,469
|
|
|
|
78,760
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
824,594
|
|
|
|
417,381
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(342,326
|
)
|
|
|
(312,878
|
)
|
Other, net
|
|
|
(6,094
|
)
|
|
|
(4,303
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(348,420
|
)
|
|
|
(317,181
|
)
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
Net decrease in short-term debt
|
|
|
(366,449
|
)
|
|
|
(35,721
|
)
|
Net proceeds from debt offering
|
|
|
445,623
|
|
|
|
|
|
Settlement of Treasury lock agreement
|
|
|
1,938
|
|
|
|
|
|
Repayment of long-term debt
|
|
|
(407,287
|
)
|
|
|
(9,945
|
)
|
Cash dividends paid
|
|
|
(90,909
|
)
|
|
|
(87,821
|
)
|
Issuance of common stock
|
|
|
19,928
|
|
|
|
19,063
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(397,156
|
)
|
|
|
(114,424
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
79,018
|
|
|
|
(14,224
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
46,717
|
|
|
|
60,725
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
125,735
|
|
|
$
|
46,501
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial
statements
5
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2009
Atmos Energy Corporation (Atmos Energy or the
Company) and our subsidiaries are engaged primarily
in the regulated natural gas distribution and transmission and
storage businesses as well as certain other nonregulated
businesses. Through our natural gas distribution business, we
deliver natural gas through sales and transportation
arrangements to approximately 3.2 million residential,
commercial, public authority and industrial customers through
our six regulated natural gas distribution divisions in the
service areas described below:
|
|
|
Division
|
|
Service Area
|
|
Atmos Energy Colorado-Kansas Division
|
|
Colorado, Kansas,
Missouri(1)
|
Atmos Energy Kentucky/Mid-States Division
|
|
Georgia(1),
Illinois(1),
Iowa(1),
Kentucky,
Missouri(1),
Tennessee,
Virginia(1)
|
Atmos Energy Louisiana Division
|
|
Louisiana
|
Atmos Energy Mid-Tex Division
|
|
Texas, including the Dallas/Fort Worth metropolitan area
|
Atmos Energy Mississippi Division
|
|
Mississippi
|
Atmos Energy West Texas Division
|
|
West Texas
|
|
|
|
(1) |
|
Denotes states where we have more limited service areas. |
In addition, we transport natural gas for others through our
distribution system. Our natural gas distribution business is
subject to federal and state regulation
and/or
regulation by local authorities in each of the states in which
our natural gas distribution divisions operate. Our corporate
headquarters and shared-services function are located in Dallas,
Texas and our customer support centers are located in Amarillo
and Waco, Texas.
Our regulated transmission and storage business consists of the
regulated operations of our Atmos Pipeline Texas
Division. The Atmos Pipeline Texas Division
transports natural gas to our Mid-Tex Division, transports
natural gas for third parties and manages five underground
storage reservoirs in Texas. We also provide ancillary services
customary to the pipeline industry including parking
arrangements, lending services and sales of inventory on hand.
Parking arrangements provide short-term interruptible storage of
gas on our pipeline. Lending services provide short-term
interruptible loans of natural gas from our pipeline to meet
market demands.
Our nonregulated businesses operate primarily in the Midwest and
Southeast and include our natural gas marketing operations and
pipeline, storage and other operations. These businesses are
operated through various wholly-owned subsidiaries of Atmos
Energy Holdings, Inc. (AEH), which is wholly owned by the
Company and based in Houston, Texas.
Our natural gas marketing operations are conducted through Atmos
Energy Marketing, LLC (AEM), which is wholly owned by AEH. AEM
provides a variety of natural gas management services to
municipalities, natural gas utility systems and industrial
natural gas customers, primarily in the Southeast and Midwest
and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana
divisions. These services consist primarily of furnishing
natural gas supplies at fixed and market-based prices, contract
negotiation and administration, load forecasting, gas storage
acquisition and management services, transportation services,
peaking sales and balancing services, capacity utilization
strategies and gas price hedging through the use of financial
instruments.
6
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS
owns and operates a 21 mile pipeline located in New
Orleans, Louisiana. This pipeline is used primarily to aggregate
gas supply for our regulated natural gas distribution division
in Louisiana and for AEM, but also provides limited third party
transportation services.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are asset management plans with regulated
affiliates of the Company which have been approved by applicable
state regulatory commissions. Generally, these asset management
plans require APS to share with our regulated customers a
portion of the profits earned from these arrangements.
Further, APS owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
pipeline capacity to meet customer demand during peak periods.
Finally, APS manages our natural gas gathering operations, which
were limited in nature as of June 30, 2009.
|
|
2.
|
Unaudited
Interim Financial Information
|
In the opinion of management, all material adjustments
(consisting of normal recurring accruals) necessary for a fair
presentation have been made to the unaudited consolidated
interim-period financial statements. These consolidated
interim-period financial statements are condensed as permitted
by the instructions to
Form 10-Q
and should be read in conjunction with the audited consolidated
financial statements of Atmos Energy Corporation included in our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. Because of
seasonal and other factors, the results of operations for the
nine-month period ended June 30, 2009 are not indicative of
our results of operations for the full 2009 fiscal year, which
ends September 30, 2009.
Significant
accounting policies
Our accounting policies are described in Note 2 to the
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008 and there have
been no changes to those policies. However, during the nine
months ended June 30, 2009, we recognized a non-recurring
$7.8 million increase in gross profit associated with a
one-time update to our estimate for gas delivered to customers
but not yet billed, resulting from base rate changes in several
jurisdictions.
During the second quarter of fiscal 2009, we updated the tax
rates used to record deferred taxes. The one-time tax benefit
resulted in a favorable impact to net income of
$11.3 million.
Additionally, during the second quarter of fiscal 2009, we
completed our annual goodwill impairment assessment. Based on
the assessment performed, we determined that our goodwill was
not impaired.
Effective October 1, 2008, the Company adopted Statement of
Financial Accounting Standards (SFAS) 157, Fair Value
Measurements, the measurement date requirements of
SFAS 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans, an amendment of FASB
Statements No. 87, 88, 106, and 132(R), SFAS 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of FASB Statement
No. 115 and SFAS 161, Disclosures about
Derivative Instruments and Hedging Activities, an amendment of
FASB Statement No. 133. Effective April 1, 2009,
the Company adopted FASB Staff Position (FSP)
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments, FSP
FAS 115-2
and
FAS 124-2,
Recognition and Presentation of
Other-Than-Temporary
Impairments, FSP
FAS 157-4,
Determining Fair Value When the Volume and Level of Activity
for Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly and
SFAS 165, Subsequent Events. Except for the adoption
of these accounting pronouncements, which are further discussed
below, there were no significant changes to our accounting
policies during the nine months ended June 30, 2009.
7
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
SFAS 157 defines fair value, establishes a framework for
measuring fair value and enhances disclosure on fair value
measurements required under other accounting pronouncements but
does not change existing guidance as to whether or not an
instrument is carried at fair value. The adoption of this
standard did not materially impact our financial position,
results of operations or cash flows. The new disclosures
required by this standard are presented in Note 4.
Effective October 1, 2008, the Company adopted the
measurement date requirements of SFAS 158 using the
remeasurement approach. Under this approach, the Company
remeasured our projected benefit obligation, fair value of plan
assets and our fiscal 2009 net periodic cost. In accordance
with the transition rules of SFAS 158, the impact of
changing the measurement date from June 30, 2008 to
September 30, 2008 decreased retained earnings by
$7.8 million, net of tax, decreased the unrecognized
actuarial loss by $9.0 million and increased our
postretirement liabilities by $3.5 million during the first
quarter of fiscal 2009.
SFAS 159 permits an entity to measure certain financial
assets and financial liabilities at fair value. The objective of
the standard is to improve financial reporting by allowing
entities to mitigate volatility in reported earnings caused by
measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. Entities
that elect the fair value option will report unrealized gains
and losses in earnings at each subsequent reporting date. The
fair value option may be elected on an
instrument-by-instrument
basis. The fair value option is irrevocable, unless a new
election date occurs. The adoption of this standard did not
impact our financial position, results of operations or cash
flows.
SFAS 161 expands the disclosure requirements for derivative
instruments and hedging activities. This statement requires
specific disclosures regarding how and why an entity uses
derivative instruments; the accounting for derivative
instruments and related hedged items; and how derivative
instruments and related hedged items affect an entitys
financial position, results of operations and cash flows. Since
SFAS 161 only requires additional disclosures concerning
derivatives and hedging activities, this standard did not have
an impact on our financial position, results of operations or
cash flows. The new disclosures required by this standard are
presented in Note 3.
In April 2009, the FASB issued FSP
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments. This FSP requires companies to disclose the
fair value of financial instruments for which it is practicable
to estimate the value and the methods and significant
assumptions used to estimate the fair value. The disclosure is
required for interim and annual reports. The disclosure
requirements of this FSP are presented in Note 4.
In April 2009, the FASB issued FSP
FAS 115-2
and
FAS 124-2,
Recognition and Presentation of
Other-Than-Temporary
Impairments. This FSP amends the
other-than-temporary
impairment guidance for debt securities to make the guidance
more operational and to improve the presentation and disclosure
of
other-than-temporary
impairments on debt and equity securities in the financial
statements. This FSP does not amend existing recognition and
measurement guidance related to
other-than-temporary
impairments of equity securities. In addition, FSP
FAS 115-2
and
FAS 124-2
expands the existing disclosure requirements about debt and
equity securities to interim reporting as well as provides new
disclosure requirements. We adopted the provisions of this FSP
for the quarter ended June 30, 2009. The adoption of FSP
FAS 115-2
and
FAS 124-2
did not impact our financial position, results of operations or
cash flows. The disclosure requirements of this FSP are
presented in Note 7.
In April 2009, the FASB issued FSP
FAS 157-4,
Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly. This FSP
provides further guidance for estimating fair value in
accordance with SFAS 157 when there has been a significant
decrease in market activity for a financial asset and also
identifies circumstances that indicate a transaction is not
orderly. The adoption of this FSP did not impact our financial
position, results of operations or cash flows.
8
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In May 2009, the FASB issued SFAS No. 165,
Subsequent Events. SFAS 165 establishes general
standards of accounting for and disclosure of events that occur
after the balance sheet date but before the date the financial
statements are issued or available to be issued. SFAS 165
requires companies to reflect in their financial statements the
effects of subsequent events that provide additional evidence
about conditions at the balance-sheet date. Subsequent events
that provide evidence about conditions that arose after the
balance-sheet date should be disclosed if the financial
statements would otherwise be misleading. We adopted the
provisions of SFAS 165 for quarter ended June 30,
2009. We have evaluated subsequent events from the balance sheet
date through the date these financial statements were filed with
the Securities and Exchange Commission. No events have occurred
subsequent to the balance sheet date that would require
recognition or disclosure in the financial statements.
Regulatory
assets and liabilities
We record certain costs as regulatory assets in accordance with
SFAS 71, Accounting for the Effects of Certain Types of
Regulation, when future recovery through customer rates is
considered probable. Regulatory liabilities are recorded when it
is probable that revenues will be reduced for amounts that will
be credited to customers through the ratemaking process.
Substantially all of our regulatory assets are recorded as a
component of deferred charges and other assets and substantially
all of our regulatory liabilities are recorded as a component of
deferred credits and other liabilities. Deferred gas costs are
recorded either in other current assets or liabilities and the
regulatory cost of removal obligation is reported separately.
Significant regulatory assets and liabilities as of
June 30, 2009 and September 30, 2008 included the
following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit costs
|
|
$
|
88,472
|
|
|
$
|
100,563
|
|
Merger and integration costs, net
|
|
|
7,268
|
|
|
|
7,586
|
|
Deferred gas costs
|
|
|
24,355
|
|
|
|
55,103
|
|
Environmental costs
|
|
|
685
|
|
|
|
980
|
|
Rate case costs
|
|
|
7,640
|
|
|
|
12,885
|
|
Deferred franchise fees
|
|
|
577
|
|
|
|
651
|
|
Deferred income taxes, net
|
|
|
343
|
|
|
|
343
|
|
Other
|
|
|
7,085
|
|
|
|
8,120
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
136,425
|
|
|
$
|
186,231
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
97,495
|
|
|
$
|
76,979
|
|
Regulatory cost of removal obligation
|
|
|
336,737
|
|
|
|
317,273
|
|
Other
|
|
|
5,429
|
|
|
|
5,639
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
439,661
|
|
|
$
|
399,891
|
|
|
|
|
|
|
|
|
|
|
Currently, our authorized rates do not include a return on
certain of our merger and integration costs; however, we recover
the amortization of these costs. Merger and integration costs,
net, are generally amortized on a straight-line basis over
estimated useful lives ranging up to 20 years.
Environmental costs have been deferred to be included in future
rate filings in accordance with rulings received from various
state regulatory commissions.
9
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Comprehensive
income
The following table presents the components of comprehensive
income (loss), net of related tax, for the three-month and
nine-month periods ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
Unrealized holding gains (losses) on investments, net of tax
expense (benefit) of $1,282 and $531 for the three months ended
June 30, 2009 and 2008 and of $(2,477) and $(140) for the
nine months ended June 30, 2009 and 2008
|
|
|
2,086
|
|
|
|
866
|
|
|
|
(4,209
|
)
|
|
|
(231
|
)
|
Other than temporary impairment of investments, net of tax
expense of $1,222 and $2,012 for the three and nine months ended
June 30, 2009
|
|
|
2,082
|
|
|
|
|
|
|
|
3,370
|
|
|
|
|
|
Amortization and unrealized gain on interest rate hedging
transactions, net of tax expense of $320 and $482 for the three
months ended June 30, 2009 and 2008 and $2,155 and $1,446
for the nine months ended June 30, 2009 and 2008
|
|
|
543
|
|
|
|
787
|
|
|
|
3,184
|
|
|
|
2,361
|
|
Net unrealized gains (losses) on commodity hedging transactions,
net of tax expense (benefit) of $16,582 and $1,850 for the three
months ended June 30, 2009 and 2008 and $(4,759) and $9,047
for the nine months ended June 30, 2009 and 2008
|
|
|
25,936
|
|
|
|
3,018
|
|
|
|
(6,379
|
)
|
|
|
14,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
32,611
|
|
|
$
|
(1,917
|
)
|
|
$
|
202,896
|
|
|
$
|
195,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss, net of tax, as of
June 30, 2009 and September 30, 2008 consisted of the
following unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
Unrealized holding gains on investments
|
|
$
|
71
|
|
|
$
|
910
|
|
Treasury lock agreements
|
|
|
(7,920
|
)
|
|
|
(11,104
|
)
|
Cash flow hedges
|
|
|
(32,132
|
)
|
|
|
(25,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(39,981
|
)
|
|
$
|
(35,947
|
)
|
|
|
|
|
|
|
|
|
|
We currently use financial instruments to mitigate commodity
price risk. Additionally, we periodically utilize financial
instruments to manage interest rate risk. The objectives and
strategies for using financial instruments have been tailored to
our regulated and nonregulated businesses. The accounting for
these financial instruments is fully described in Note 2 to
the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. Currently, we
utilize financial instruments in our natural gas distribution,
natural gas marketing and pipeline, storage and other segments.
However, our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from
10
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
an independent counterparty. On a consolidated basis, these
financial instruments are reported in the natural gas marketing
segment. We currently do not manage commodity price risk with
financial instruments in our regulated transmission and storage
segment.
Our financial instruments do not contain any credit-risk-related
or other contingent features that could cause accelerated
payments when our financial instruments are in net liability
positions.
Regulated
Commodity Risk Management Activities
In our natural gas distribution segment, our customers are
exposed to the effect of volatile natural gas prices. We manage
this exposure through a combination of physical storage,
fixed-price forward contracts and financial instruments,
primarily
over-the-counter
swap and option contracts, in an effort to minimize the impact
of natural gas price volatility on our customers during the
winter heating season.
Our natural gas distribution gas supply department is
responsible for executing this segments commodity risk
management activities in conformity with regulatory
requirements. In jurisdictions where we are permitted to
mitigate commodity price risk through financial instruments, the
relevant regulatory authorities may establish the level of
heating season gas purchases that can be hedged. If the
regulatory authority does not establish this level, we typically
seek to hedge between 25 and 50 percent of anticipated
heating season gas purchases using financial instruments. For
the
2008-2009
heating season, in the jurisdictions where we are permitted to
utilize financial instruments, we hedged approximately
27 percent, or 24.3 Bcf of the winter flowing gas
requirements. We have not designated these financial instruments
as hedges pursuant to SFAS 133, Accounting for
Derivative Instruments and Hedging Activities.
The costs associated with and the gains and losses arising from
the use of financial instruments to mitigate commodity price
risk are included in our purchased gas adjustment mechanisms in
accordance with regulatory requirements. Therefore, changes in
the fair value of these financial instruments are initially
recorded as a component of deferred gas costs and recognized in
the consolidated statement of income as a component of purchased
gas cost when the related costs are recovered through our rates
and recognized in revenue in accordance with SFAS 71.
Accordingly, there is no earnings impact to our natural gas
distribution segment as a result of the use of financial
instruments.
Nonregulated
Commodity Risk Management Activities
Our natural gas marketing segment, through AEM, aggregates and
purchases gas supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request.
We also perform asset optimization activities in both our
natural gas marketing segment and pipeline, storage and other
segment. Through asset optimization activities, we seek to
maximize the economic value associated with the storage and
transportation capacity we own or control. We attempt to meet
this objective by engaging in natural gas storage transactions
in which we seek to find and profit from pricing differences
that occur over time. We purchase physical natural gas and then
sell financial instruments at advantageous prices to lock in a
gross profit margin. We also seek to participate in transactions
in which we combine the natural gas commodity and transportation
costs to minimize costs incurred to serve our customers by
identifying the lowest cost alternative within the natural gas
supplies, transportation and markets to which we have access.
Through the use of transportation and storage services and
financial instruments, we also seek to capture gross profit
margin through the arbitrage of pricing differences that exist
in various locations and by recognizing pricing differences that
occur over time. Over time, gains and losses on the sale of
storage gas inventory will be offset by gains and losses on the
financial instruments, resulting in the realization of the
economic gross profit margin we anticipated at the time we
structured the original transaction.
11
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As a result of these activities, our nonregulated operations are
exposed to risks associated with changes in the market price of
natural gas. We manage our exposure to such risks through a
combination of physical storage and financial instruments,
including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. Futures contracts provide the right to buy or
sell the commodity at a fixed price in the future. Option
contracts provide the right, but not the requirement, to buy or
sell the commodity at a fixed price. Swap contracts require
receipt of payment for the commodity based on the difference
between a fixed price and the market price on the settlement
date.
We use financial instruments, designated as cash flow hedges of
anticipated purchases and sales at index prices, to mitigate the
commodity price risk in our natural gas marketing segment
associated with deliveries under fixed-priced forward contracts
to deliver gas to customers. These financial instruments have
maturity dates ranging from one to 43 months. The effective
portion of the unrealized gains and losses arising from the use
of cash flow hedges is recorded as a component of accumulated
other comprehensive income (AOCI) on the balance sheet. Amounts
associated with cash flow hedges recognized in the income
statement include (i) the amount of unrealized gain or loss
that has been reclassified from AOCI when the hedged volumes are
sold and (ii) the amount of ineffectiveness associated with
these hedges in the period the ineffectiveness arises.
We use financial instruments, designated as fair value hedges,
to hedge the exposure to changes in the fair value of our
natural gas inventory used in our asset optimization activities
in our natural gas marketing and pipeline, storage and other
segments. Therefore, gains and losses arising from these
financial instruments should offset the changes in the fair
value of the hedged item to the extent the hedging relationship
is effective. Ineffectiveness is recognized in the income
statement in the period the ineffectiveness arises.
Our natural gas marketing segment also uses storage swaps and
futures to capture additional storage arbitrage opportunities
that arise subsequent to the execution of the original fair
value hedge associated with our physical natural gas inventory,
basis swaps to insulate and protect the economic value of our
fixed price and storage books and various
over-the-counter
and exchange-traded options. These financial instruments have
not been designated as hedges pursuant to SFAS 133,
Accounting for Derivative Instruments and Hedging
Activities.
Our nonregulated risk management activities are controlled
through various risk management policies and procedures. Our
Audit Committee has oversight responsibility for our
nonregulated risk management limits and policies. A risk
committee, comprised of corporate and business unit officers, is
responsible for establishing and enforcing our nonregulated risk
management policies and procedures.
Under our risk management policies, we seek to match our
financial instrument positions to our physical storage positions
as well as our expected current and future sales and purchase
obligations to maintain no open positions at the end of each
trading day. The determination of our net open position as of
any day, however, requires us to make assumptions as to future
circumstances, including the use of gas by our customers in
relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. Our operations can also be affected by
intraday fluctuations of gas prices, since the price of natural
gas purchased or sold for future delivery earlier in the day may
not be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on June 30, 2009, AEH
had net open positions (including existing storage) of
0.3 Bcf.
Interest
Rate Risk Management Activities
In March 2009, we entered into a Treasury lock agreement to fix
the Treasury yield component of the interest cost associated
with our $450 million 8.50% senior notes (the Senior
Notes Offering), which was completed on March 26, 2009. The
Senior Notes Offering is discussed in Note 5. We designated
this Treasury
12
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
lock as a cash flow hedge of an anticipated transaction. This
Treasury lock was settled on March 23, 2009 with the
receipt of $1.9 million from the counterparty due to an
increase in the 10 year Treasury rates between inception of
the Treasury lock and settlement. Because the Treasury lock was
effective, the net $1.2 million unrealized gain was
recorded as a component of accumulated other comprehensive
income and will be recognized as a component of interest expense
over the 10 year life of the senior notes.
In prior years, we similarly managed interest rate risk by
entering into Treasury lock agreements to fix the Treasury yield
component of the interest cost associated with anticipated
financings. These Treasury locks were settled at various times
at a net loss. These realized gains and losses were recorded as
a component of accumulated other comprehensive income (loss) and
are being recognized as a component of interest expense over the
life of the associated notes from the date of settlement. The
remaining amortization periods for these Treasury locks extend
through fiscal 2035. However, the majority of the remaining
amounts of these Treasury locks will be recognized through
fiscal 2019.
Quantitative
Disclosures Related to Financial Instruments
The following tables present detailed information concerning the
impact of financial instruments on our condensed consolidated
balance sheet and income statements.
As of June 30, 2009, our financial instruments were
comprised of both long and short commodity positions. A long
position is a contract to purchase the commodity, while a short
position is a contract to sell the commodity. As of
June 30, 2009, we had net long/(short) commodity contracts
outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
Hedge
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
Contract Type
|
|
Designation
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
|
|
|
Quantity (MMcf)
|
|
|
Commodity contracts
|
|
Fair Value
|
|
|
|
|
|
|
(22,905
|
)
|
|
|
(2,050
|
)
|
|
|
Cash Flow
|
|
|
|
|
|
|
31,993
|
|
|
|
(4,118
|
)
|
|
|
Not designated
|
|
|
21,702
|
|
|
|
84,606
|
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,702
|
|
|
|
93,694
|
|
|
|
(6,219
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Instruments on the Balance Sheet
The following tables present the fair value and balance sheet
classification of our financial instruments by operating segment
as of June 30, 2009 and September 30, 2008. As
required by SFAS 161, the fair value amounts below are
presented on a gross basis and do not reflect the netting of
asset and liability positions permitted under the terms of our
master netting arrangements. Further, the amounts below do not
include $20.6 million and $56.6 million of cash held
on deposit in margin accounts as of June 30, 2009 and
September 30, 2008 to collateralize certain financial
instruments. Therefore, these gross balances are not indicative
of either our actual credit exposure or net economic exposure.
Additionally, the amounts below will
13
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
not be equal to the amounts presented on our condensed
consolidated balance sheet, nor will they be equal to the fair
value information presented for our financial instruments in
Note 4.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
71,992
|
|
|
$
|
71,992
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
6,383
|
|
|
|
6,383
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(71,878
|
)
|
|
|
(71,878
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(1,150
|
)
|
|
|
(1,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
5,347
|
|
|
|
5,347
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
1,233
|
|
|
|
28,887
|
|
|
|
30,120
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
6,381
|
|
|
|
6,381
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(22,945
|
)
|
|
|
(20,428
|
)
|
|
|
(43,373
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(316
|
)
|
|
|
(1,743
|
)
|
|
|
(2,059
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(22,028
|
)
|
|
|
13,097
|
|
|
|
(8,931
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(22,028
|
)
|
|
$
|
18,444
|
|
|
$
|
(3,584
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
|
|
|
|
Balance Sheet Location
|
|
Distribution
|
|
|
Marketing(1)
|
|
|
Total
|
|
|
|
|
|
(In thousands)
|
|
|
September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
$
|
|
|
|
$
|
101,191
|
|
|
$
|
101,191
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
4,984
|
|
|
|
4,984
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
|
|
|
|
(89,397
|
)
|
|
|
(89,397
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
|
|
|
|
(206
|
)
|
|
|
(206
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
16,572
|
|
|
|
16,572
|
|
Not Designated As Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current assets
|
|
|
|
|
|
|
20,010
|
|
|
|
20,010
|
|
Noncurrent commodity contracts
|
|
Deferred charges and other assets
|
|
|
|
|
|
|
1,093
|
|
|
|
1,093
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current commodity contracts
|
|
Other current liabilities
|
|
|
(58,566
|
)
|
|
|
(20,145
|
)
|
|
|
(78,711
|
)
|
Noncurrent commodity contracts
|
|
Deferred credits and other liabilities
|
|
|
(5,111
|
)
|
|
|
(988
|
)
|
|
|
(6,099
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
(63,677
|
)
|
|
|
(30
|
)
|
|
|
(63,707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Financial Instruments
|
|
|
|
$
|
(63,677
|
)
|
|
$
|
16,542
|
|
|
$
|
(47,135
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
14
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Impact of
Financial Instruments on the Income Statement
The following tables present the impact that financial
instruments had on our condensed consolidated income statement,
by operating segment, as applicable, for the three and nine
months ended June 30, 2009 and 2008.
Hedge ineffectiveness for our natural gas marketing and pipeline
storage and other segments is recorded as a component of
unrealized gross profit and primarily results from differences
in the location and timing of the derivative instrument and the
hedged item. Hedge ineffectiveness could materially affect our
results of operations for the reported period. For the three
months ended June 30, 2009 and 2008 we recognized a gain
(loss) arising from fair value and cash flow hedge
ineffectiveness of $0.2 million and $(4.7) million.
For the nine months ended June 30, 2009 and 2008 we
recognized a gain arising from fair value and cash flow hedge
ineffectiveness of $24.7 million and $40.6 million.
Additional information regarding ineffectiveness recognized in
the income statement is included in the tables below.
Fair
Value Hedges
The impact of commodity contracts designated as fair value
hedges and the related hedged item on our condensed consolidated
income statement for the three and nine months ended
June 30, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
2,710
|
|
|
$
|
1,390
|
|
|
$
|
4,100
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
3,929
|
|
|
|
(741
|
)
|
|
|
3,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
6,639
|
|
|
$
|
649
|
|
|
$
|
7,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
678
|
|
|
$
|
|
|
|
$
|
678
|
|
Timing ineffectiveness
|
|
|
5,961
|
|
|
|
649
|
|
|
|
6,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,639
|
|
|
$
|
649
|
|
|
$
|
7,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
(50,391
|
)
|
|
$
|
(2,049
|
)
|
|
$
|
(52,440
|
)
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
46,765
|
|
|
|
1,431
|
|
|
|
48,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
(3,626
|
)
|
|
$
|
(618
|
)
|
|
$
|
(4,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(2,402
|
)
|
|
$
|
|
|
|
$
|
(2,402
|
)
|
Timing ineffectiveness
|
|
|
(1,224
|
)
|
|
|
(618
|
)
|
|
|
(1,842
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,626
|
)
|
|
$
|
(618
|
)
|
|
$
|
(4,244
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
48,263
|
|
|
$
|
7,435
|
|
|
$
|
55,698
|
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
(26,493
|
)
|
|
|
(2,731
|
)
|
|
|
(29,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
21,770
|
|
|
$
|
4,704
|
|
|
$
|
26,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
4,958
|
|
|
$
|
|
|
|
$
|
4,958
|
|
Timing ineffectiveness
|
|
|
16,812
|
|
|
|
4,704
|
|
|
|
21,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
21,770
|
|
|
$
|
4,704
|
|
|
$
|
26,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
Marketing
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Commodity contracts
|
|
$
|
(66,612
|
)
|
|
$
|
(662
|
)
|
|
$
|
(67,274
|
)
|
Fair value adjustment for natural gas inventory designated as
the hedged item
|
|
|
104,288
|
|
|
|
3,841
|
|
|
|
108,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
37,676
|
|
|
$
|
3,179
|
|
|
$
|
40,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact on revenue is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(1,185
|
)
|
|
$
|
|
|
|
$
|
(1,185
|
)
|
Timing ineffectiveness
|
|
|
38,861
|
|
|
|
3,179
|
|
|
|
42,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
37,676
|
|
|
$
|
3,179
|
|
|
$
|
40,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis ineffectiveness arises from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the hedge instruments. Timing
ineffectiveness arises due to changes in the difference between
the spot price and the futures price, as well as the difference
between the timing of the settlement of the futures and the
valuation of the underlying physical commodity. As the commodity
contract nears the settlement date, spot to forward price
differences should converge, which should reduce or eliminate
the impact of this ineffectiveness on revenue.
16
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
Flow Hedges
The impact of cash flow hedges on our condensed consolidated
income statements for the three and nine months ended
June 30, 2009 and 2008 is presented below. Note that this
presentation does not reflect the financial impact arising from
the hedged physical transaction. Therefore, this presentation is
not indicative of the economic gross profit we realized when the
underlying physical and financial transactions were settled.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Loss reclassified from AOCI into revenue for effective portion
of commodity contracts
|
|
$
|
|
|
|
$
|
(36,669
|
)
|
|
$
|
(2,503
|
)
|
|
$
|
(39,172
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(7,120
|
)
|
|
|
|
|
|
|
(7,120
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(43,789
|
)
|
|
|
(2,503
|
)
|
|
|
(46,292
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(863
|
)
|
|
|
|
|
|
|
|
|
|
|
(863
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(863
|
)
|
|
$
|
(43,789
|
)
|
|
$
|
(2,503
|
)
|
|
$
|
(47,155
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain reclassified from AOCI into revenue for effective portion
of commodity contracts
|
|
$
|
|
|
|
$
|
10,040
|
|
|
$
|
57
|
|
|
$
|
10,097
|
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(406
|
)
|
|
|
|
|
|
|
(406
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
9,634
|
|
|
|
57
|
|
|
|
9,691
|
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(1,269
|
)
|
|
$
|
9,634
|
|
|
$
|
57
|
|
|
$
|
8,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(142,986
|
)
|
|
$
|
25,213
|
|
|
$
|
(117,773
|
)
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(1,748
|
)
|
|
|
|
|
|
|
(1,748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(144,734
|
)
|
|
|
25,213
|
|
|
|
(119,521
|
)
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(3,401
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,401
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(3,401
|
)
|
|
$
|
(144,734
|
)
|
|
$
|
25,213
|
|
|
$
|
(122,922
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
Gas
|
|
|
Gas
|
|
|
Storage
|
|
|
|
|
|
|
Distribution
|
|
|
Marketing
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Gain (loss) reclassified from AOCI into revenue for effective
portion of commodity contracts
|
|
$
|
|
|
|
$
|
(3,744
|
)
|
|
$
|
9,334
|
|
|
$
|
5,590
|
|
Loss arising from ineffective portion of commodity contracts
|
|
|
|
|
|
|
(281
|
)
|
|
|
|
|
|
|
(281
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
|
|
|
|
|
(4,025
|
)
|
|
|
9,334
|
|
|
|
5,309
|
|
Net loss on settled Treasury lock agreements reclassified from
AOCI into interest expense
|
|
|
(3,807
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,807
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Impact from Cash Flow Hedges
|
|
$
|
(3,807
|
)
|
|
$
|
(4,025
|
)
|
|
$
|
9,334
|
|
|
$
|
1,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the gains and losses arising from
hedging transactions that were recognized as a component of
other comprehensive income (loss), net of taxes, for the three
and nine months ended June 30, 2009 and 2008. The amounts
included in the table below exclude gains and losses arising
from ineffectiveness because these amounts are immediately
recognized in the income statement as incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,221
|
|
|
$
|
|
|
Forward commodity contracts
|
|
|
2,041
|
|
|
|
9,278
|
|
|
|
(78,220
|
)
|
|
|
18,227
|
|
Recognition of (gains) losses in earnings due to
settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
543
|
|
|
|
787
|
|
|
|
1,963
|
|
|
|
2,361
|
|
Forward commodity contracts
|
|
|
23,895
|
|
|
|
(6,260
|
)
|
|
|
71,841
|
|
|
|
(3,466
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) from hedging, net of
tax(1)
|
|
$
|
26,479
|
|
|
$
|
3,805
|
|
|
$
|
(3,195
|
)
|
|
$
|
17,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
The following amounts, net of deferred taxes, represent the
expected recognition in earnings of the deferred losses recorded
in AOCI associated with our financial instruments, based upon
the fair values of these financial instruments as of
June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Commodity
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Next twelve months
|
|
$
|
(1,687
|
)
|
|
$
|
(30,303
|
)
|
|
$
|
(31,990
|
)
|
Thereafter
|
|
|
(6,233
|
)
|
|
|
(1,829
|
)
|
|
|
(8,062
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(1)
|
|
$
|
(7,920
|
)
|
|
$
|
(32,132
|
)
|
|
$
|
(40,052
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 37 percent
comprised of the effective rates in each taxing jurisdiction. |
18
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Financial
Instruments Not Designated as Hedges
The impact of financial instruments that have not been
designated as hedges on our condensed consolidated income
statements for the three and nine months ended June 30,
2009 and 2008 is presented below. Note that this presentation
does not reflect the expected gains or losses arising from the
underlying physical transactions associated with these financial
instruments. Therefore, this presentation is not indicative of
the economic gross profit we realized when the underlying
physical and financial transactions were settled.
As discussed above, financial instruments used in our natural
gas distribution segment are not designated as hedges. However,
there is no earnings impact to our natural gas distribution
segment as a result of the use of these financial instruments
because the gains and losses arising from the use of these
financial instruments are recognized in the consolidated
statement of income as a component of purchased gas cost when
the related costs are recovered through our rates and recognized
in revenue. Accordingly, the impact of these financial
instruments is excluded from this presentation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Natural gas marketing commodity contracts
|
|
$
|
6,167
|
|
|
$
|
(12,786
|
)
|
|
$
|
12,928
|
|
|
$
|
(26,580
|
)
|
Pipeline, storage and other commodity contracts
|
|
|
(6,853
|
)
|
|
|
2,594
|
|
|
|
(6,753
|
)
|
|
|
1,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on revenue
|
|
$
|
(686
|
)
|
|
$
|
(10,192
|
)
|
|
$
|
6,175
|
|
|
$
|
(24,875
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Fair
Value Measurements
|
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS 157, Fair Value Measurements,
which defines fair value, establishes a framework for measuring
fair value in generally accepted accounting principles (GAAP)
and expands disclosures about fair value measurements. This
Statement does not require any new fair value measurements;
rather it provides guidance on how to perform fair value
measurements as required or permitted under previous accounting
pronouncements.
We prospectively adopted the provisions of SFAS 157 on
October 1, 2008 for most of the financial assets and
liabilities recorded on our balance sheet at fair value.
Adoption of this statement for these assets and liabilities did
not have a material impact on our financial position, results of
operations or cash flows.
In February 2008, the FASB issued FSP
FAS 157-2,
Effective Date of FASB Statement No. 157, which
provided a one-year deferral of SFAS 157 for nonrecurring
fair value measurements associated with our nonfinancial assets
and liabilities. Under this partial deferral, SFAS 157 will
not be effective until October 1, 2009 for fair value
measurements for the following:
|
|
|
|
|
Asset retirement obligations
|
|
|
|
Most nonfinancial assets and liabilities that may be acquired in
a business combination
|
|
|
|
Impairment analyses performed for nonfinancial assets
|
We believe the adoption of SFAS 157 for the reporting of
these nonfinancial assets and liabilities will not have a
material impact on our financial position, results of operations
or cash flows.
In October 2008, the FASB issued FSP
FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset Is Not Active, which clarified the
application of SFAS 157 in inactive markets. This FSP did
not impact our financial position, results of operations or cash
flows.
SFAS 157 also applies to the valuation of our pension and
post-retirement plan assets. The adoption of this standard did
not affect these valuations because SFAS 157 specifically
excluded pension and post-retirement assets from its prescribed
disclosure provisions. Accordingly, these plan assets are not
included in the tabular disclosures below. However, in December
2008, the FASB issued FSP FAS 132(R)-1
Employers
19
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Disclosures about Postretirement Benefit Plan Assets,
which will, among other things, require disclosure about fair
value measurements similar to those required by SFAS 157.
This FSP will impact our annual disclosure requirements
beginning in fiscal 2010.
In April 2009, the FASB issued FSP
FAS 157-4,
Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly. This FSP
provides further guidance for estimating fair value in
accordance with SFAS 157 when there has been a significant
decrease in market activity for a financial asset and also
identifies circumstances that indicate a transaction is not
orderly. The adoption of this FSP did not impact our financial
position, results of operations or cash flows.
In April 2009, the FASB issued FSP
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments. This FSP requires companies to disclose the
fair value of financial instruments for which it is practicable
to estimate the value and the methods and significant
assumptions used to estimate the fair value. We have adopted the
disclosure requirements of this FSP, which are presented below.
Determining
Fair Value
SFAS 157 defines fair value as the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the
measurement date (exit price). We primarily use quoted market
prices and other observable market pricing information in
valuing our financial assets and liabilities and minimize the
use of unobservable pricing inputs in our measurements.
Prices actively quoted on national exchanges are used to
determine the fair value of most of our assets and liabilities
recorded on our balance sheet at fair value. Within our
nonregulated operations, we utilize a mid-market pricing
convention (the mid-point between the bid and ask prices) as a
practical expedient for determining fair value measurement, as
permitted under SFAS 157. Values derived from these sources
reflect the market in which transactions involving these
financial instruments are executed. We utilize models and other
valuation methods to determine fair value when external sources
are not available. Values are adjusted to reflect the potential
impact of an orderly liquidation of our positions over a
reasonable period of time under then-current market conditions.
We believe the market prices and models used to value these
assets and liabilities represent the best information available
with respect to closing exchange and
over-the-counter
quotations, time value and volatility factors underlying the
assets and liabilities.
Fair-value estimates also consider our own creditworthiness and
the creditworthiness of the counterparties involved. Our
counterparties consist primarily of financial institutions and
major energy companies. This concentration of counterparties may
materially impact our exposure to credit risk resulting from
market, economic or regulatory conditions. Recent adverse
developments in the global financial and credit markets have
made it more difficult and more expensive for companies to
access the short-term capital markets, which may negatively
impact the creditworthiness of our counterparties. A continued
tightening of the credit markets could cause more of our
counterparties to fail to perform. We seek to minimize
counterparty credit risk through an evaluation of their
financial condition and credit ratings and the use of collateral
requirements under certain circumstances.
SFAS 157 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value based on
observable and unobservable data. The hierarchy categorizes the
inputs into three levels, with the highest priority given to
unadjusted quoted prices in active markets for identical assets
and liabilities (Level 1) and the lowest priority
given to unobservable inputs (Level 3). The levels of the
hierarchy are described below:
Level 1 Unadjusted quoted prices
in active markets for identical assets or liabilities. An active
market for the asset or liability is defined as a market in
which transactions for the asset or liability occur with
sufficient frequency and volume to provide pricing information
on an ongoing basis. Our Level 1 measurements consist
primarily of exchange-traded financial instruments, gas stored
underground that has been designated as the hedged item in a
fair value hedge and our
available-for-sale
securities.
20
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Level 2 Pricing inputs other than
quoted prices included in Level 1 that are either directly
or indirectly observable for the asset or liability as of the
reporting date. These inputs are derived principally from, or
corroborated by, observable market data. Our Level 2
measurements primarily consist of non-exchange-traded financial
instruments, such as
over-the-counter
options and swaps where market data for pricing is observable.
Level 3 Generally unobservable
pricing inputs which are developed based on the best information
available, including our own internal data, in situations where
there is little if any market activity for the asset or
liability at the measurement date. The pricing inputs utilized
reflect what a market participant would use to determine fair
value. Currently, we have no assets or liabilities recorded at
fair value that would qualify for Level 3 reporting.
Quantitative
Disclosures
Financial
Instruments
The classification of our fair value measurements requires
judgment regarding the degree to which market data are
observable or corroborated by observable market data. The
following table summarizes, by level within the fair value
hierarchy, our assets and liabilities that were accounted for at
fair value on a recurring basis as of June 30, 2009. As
required under SFAS 157, assets and liabilities are
categorized in their entirety based on the lowest level of input
that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
|
|
|
Significant
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
Prices in
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Netting and
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Cash
|
|
|
June 30,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Collateral(1)
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
1,233
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,233
|
|
Natural gas marketing segment
|
|
|
40,494
|
|
|
|
73,149
|
|
|
|
|
|
|
|
(73,722
|
)
|
|
|
39,921
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments
|
|
|
40,494
|
|
|
|
74,382
|
|
|
|
|
|
|
|
(73,722
|
)
|
|
|
41,154
|
|
Hedged portion of gas stored underground
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing segment
|
|
|
79,604
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79,604
|
|
Pipeline, storage and other
segment(2)
|
|
|
7,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas stored underground
|
|
|
86,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,627
|
|
Available-for-sale
securities
|
|
|
38,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
165,977
|
|
|
$
|
74,382
|
|
|
$
|
|
|
|
$
|
(73,722
|
)
|
|
$
|
166,637
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas distribution segment
|
|
$
|
|
|
|
$
|
23,261
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
23,261
|
|
Natural gas marketing segment
|
|
|
72,410
|
|
|
|
22,789
|
|
|
|
|
|
|
|
(94,336
|
)
|
|
|
863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
72,410
|
|
|
$
|
46,050
|
|
|
$
|
|
|
|
$
|
(94,336
|
)
|
|
$
|
24,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This column reflects adjustments to our gross financial
instrument assets and liabilities to reflect netting permitted
under our master netting agreements and FSP
FIN 39-1.
In addition, as of June 30, 2009, we had $20.6 million
of cash held in margin accounts to collateralize certain
financial instruments. Of this amount, $0.1 million was
used to offset financial instruments in a liability position.
The remaining $20.5 million has been reflected as a
financial instrument asset. |
|
(2) |
|
Our pipeline, storage and other segment uses financial
instruments acquired from AEM on the same terms that AEM
received from an independent counterparty. On a consolidated
basis, these financial instruments are reported in the natural
gas marketing segment; however, the underlying hedged item is
reported in the pipeline, storage and other segment. |
21
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Fair Value Measures
In addition to the financial instruments above, we have several
nonfinancial assets and liabilities subject to fair value
measures. These assets and liabilities include cash and cash
equivalents, accounts receivable, accounts payable, debt, asset
retirement obligations and pension and post-retirement plan
assets. As noted above, fair value disclosures for asset
retirement obligations and pension and post-retirement plan
assets are not currently effective for us. We record cash and
cash equivalents, accounts receivable, accounts payable and debt
at carrying value. For cash and cash equivalents, accounts
receivable and accounts payable, we consider carrying value to
materially approximate fair value due to the short-term nature
of these assets and liabilities. The fair value of our debt is
determined using a discounted cash flow analysis based upon
borrowing rates currently available to us, the remaining average
maturities and our credit rating. The following table presents
the carrying value and fair value of our debt as of
June 30, 2009:
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
(In thousands)
|
|
|
Carrying Amount
|
|
$
|
2,172,893
|
|
Fair Value
|
|
$
|
2,068,388
|
|
The fair value as of June 30, 2009 was calculated utilizing
discount rates ranging from 3.5 percent to
7.2 percent, remaining average maturities ranging from one
to 26 years, and a credit adjustment of 2.9 percent.
Long-term
debt
Long-term debt at June 30, 2009 and September 30, 2008
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Unsecured 4.00% Senior Notes, redeemed April 2009
|
|
$
|
|
|
|
$
|
400,000
|
|
Unsecured 7.375% Senior Notes, due 2011
|
|
|
350,000
|
|
|
|
350,000
|
|
Unsecured 10% Notes, due 2011
|
|
|
2,303
|
|
|
|
2,303
|
|
Unsecured 5.125% Senior Notes, due 2013
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 4.95% Senior Notes, due 2014
|
|
|
500,000
|
|
|
|
500,000
|
|
Unsecured 6.35% Senior Notes, due 2017
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 8.50% Senior Notes, due 2019
|
|
|
450,000
|
|
|
|
|
|
Unsecured 5.95% Senior Notes, due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A,
1995-2,
6.27%, due December 2010
|
|
|
10,000
|
|
|
|
10,000
|
|
Series A,
1995-1,
6.67%, due 2025
|
|
|
10,000
|
|
|
|
10,000
|
|
Unsecured 6.75% Debentures, due 2028
|
|
|
150,000
|
|
|
|
150,000
|
|
Other term notes due in installments through 2013
|
|
|
590
|
|
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,172,893
|
|
|
|
2,123,612
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on unsecured senior notes and debentures
|
|
|
(3,367
|
)
|
|
|
(3,035
|
)
|
Current maturities
|
|
|
(131
|
)
|
|
|
(785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,169,395
|
|
|
$
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
22
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On March 26, 2009, we closed our Senior Notes Offering. The
effective interest rate on these notes is 8.69 percent,
after giving effect to the settlement of the $450 million
Treasury lock discussed in Note 3. Most of the net proceeds
of approximately $446 million were used to redeem our
$400 million 4.00% unsecured senior notes on April 30,
2009, prior to their October 2009 maturity. In connection with
the repayment of the $400 million 4.00% unsecured senior
notes, we paid a $6.6 million call premium in accordance
with the terms of the senior notes and accrued interest of
approximately $0.6 million. The remaining net proceeds were
used for general corporate purposes.
Short-term
debt
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply our customers needs could significantly affect our
borrowing requirements. Our short-term borrowings typically
reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide approximately $1.3 billion of working
capital funding. At June 30, 2009, there was no short-term
debt outstanding. At September 30, 2008, there was
$350.5 million of short-term debt outstanding, comprised of
$330.5 million outstanding under our bank credit facilities
and $20.0 million outstanding under our commercial paper
program. We also use intercompany credit facilities to
supplement the funding provided by these third-party committed
credit facilities. These facilities are described in greater
detail below.
Regulated
Operations
We fund our regulated operations as needed primarily through a
$566.7 million commercial paper program and three committed
revolving credit facilities with third-party lenders that
provide approximately $800 million of working capital
funding. The first facility is a five-year unsecured facility,
expiring December 2011, that bears interest at a base rate or at
a LIBOR-based rate for the applicable interest period, plus a
spread ranging from 0.30 percent to 0.75 percent,
based on the Companys credit ratings. This credit facility
serves as a backup liquidity facility for our commercial paper
program. At the time this credit facility was established,
borrowings under this facility were limited to
$600 million. However, in September 2008, the limit on
borrowings was effectively reduced to $566.7 million after
one lender with a 5.55% share of the commitments ceased funding
under the facility. On March 30, 2009, the credit facility
was amended to reflect this reduction. At June 30, 2009,
there were no borrowings under this facility and
$566.7 million was available.
The second facility is a $212.5 million unsecured
364-day
facility expiring October 2009, that bears interest at a base
rate or at a LIBOR-based rate for the applicable interest
period, plus a spread ranging from 1.25 percent to
2.50 percent, based on the Companys credit ratings.
At June 30, 2009, there were no borrowings outstanding
under this facility.
The third facility was an $18 million unsecured facility
that bore interest at a daily negotiated rate, generally based
on the Federal Funds rate plus a variable margin. This facility
expired on March 31, 2009 and was replaced with a
$25 million unsecured facility effective April 1, 2009
that bears interest at a daily negotiated rate. At June 30,
2009, there were no borrowings outstanding under this facility.
The availability of funds under these credit facilities is
subject to conditions specified in the respective credit
agreements, all of which we currently satisfy. These conditions
include our compliance with financial covenants and the
continued accuracy of representations and warranties contained
in these agreements. We are required by the financial covenants
in each of these facilities to maintain, at the end of each
fiscal quarter, a ratio of total debt to total capitalization of
no greater than 70 percent. At June 30, 2009, our
total-debt-to-
23
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
total-capitalization ratio, as defined, was 52 percent. In
addition, both the interest margin over the Eurodollar rate and
the fee that we pay on unused amounts under each of these
facilities are subject to adjustment depending upon our credit
ratings.
In addition to these third-party facilities, our regulated
operations have a $200 million intercompany revolving
credit facility with AEH. Through December 31, 2008, this
facility bore interest at the one-month LIBOR rate plus
0.20 percent. In January 2009, this facility was replaced
with a new $200 million 364 day-facility that bears
interest at the lower of (i) the one-month LIBOR rate plus
0.45 percent or (ii) the marginal borrowing rate
available to the Company on the date of borrowing. The marginal
borrowing rate is defined as the lower of (i) a rate based
upon the lower of the Prime Rate or the Eurodollar rate under
the five year revolving credit facility or (ii) the lowest
rate outstanding under the commercial paper program. Applicable
state regulatory commissions have approved the new facility
through December 31, 2009. There was $40.3 million
outstanding under this facility at June 30, 2009.
Nonregulated
Operations
On December 30, 2008, AEM and the participating banks
amended and restated AEMs former uncommitted credit
facility, primarily to convert the $580 million uncommitted
demand credit facility to a
364-day
$375 million committed revolving credit facility and extend
it to December 29, 2009. Effective April 1, 2009, the
borrowing base was increased to $450 million through the
exercise of an accordion feature in the facility.
The amended facility also adds a swing line loan feature;
adjusts the interest rate on borrowings as discussed below and
increases the fees paid to reflect the facilitys
conversion to a committed facility and current credit market
conditions. The swing line loan feature allows AEM to borrow, on
a same day basis, an amount ranging from $17 million to
$27 million based on the terms of an election within the
agreement.
AEM uses this facility primarily to issue letters of credit and,
on a less frequent basis, to borrow funds for gas purchases and
other working capital needs. At AEMs option, borrowings
made under the credit facility are based on a base rate or an
offshore rate, in each case plus an applicable margin. The base
rate is a floating rate equal to the higher of:
(a) 0.50 percent per annum above the latest federal
funds rate; (b) the per annum rate of interest established
by BNP Paribas from time to time as its prime rate
or base rate for U.S. dollar loans; (c) an
offshore rate (based on LIBOR with a one-month interest period)
as in effect from time to time; and (d) the cost of
funds rate based on an average of interest rates reported
by one or more of the lenders to the administrative agent. The
offshore rate is a floating rate equal to the higher of
(a) an offshore rate based upon LIBOR for the applicable
interest period; and (b) a cost of funds rate
referred to above. In the case of both base rate and offshore
rate loans, the applicable margin ranges from 2.250 percent
to 2.625 percent per annum, depending on the excess
tangible net worth of AEM, as defined in the credit facility.
This facility is collateralized by substantially all of the
assets of AEM and is guaranteed by AEH.
At June 30, 2009, there were no borrowings outstanding
under this credit facility. However, at June 30, 2009, AEM
letters of credit totaling $24.0 million had been issued
under the facility, which reduced the amount available by a
corresponding amount. The amount available under this credit
facility is also limited by various covenants, including
covenants based on working capital. Under the most restrictive
covenant, the amount available to AEM under this credit facility
was $100.6 million at June 30, 2009.
AEM is required by the financial covenants in this facility to
maintain a ratio of total liabilities to tangible net worth that
does not exceed a maximum of 5 to 1. At June 30, 2009,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 0.86 to 1. Additionally, AEM must maintain minimum
levels of net working capital and net worth ranging from
$75 million to $112.5 million. As defined in the
financial covenants, at June 30, 2009, AEMs net
working capital was $195.5 million and its tangible net
worth was $210.5 million.
24
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
To supplement borrowings under this facility, through
December 31, 2008, AEM had a $200 million intercompany
demand credit facility with AEH, which bore interest at the rate
for AEMs offshore borrowings under its committed credit
facility plus 0.75 percent. Amounts outstanding under this
facility are subordinated to AEMs committed credit
facility. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. There were no
borrowings outstanding under this facility at June 30, 2009.
Finally, through December 31, 2008, AEH had a
$200 million intercompany demand credit facility with AEC,
which bore interest at the rate for AEMs offshore
borrowings under its committed credit facility plus
0.75 percent. This facility was replaced with another
$200 million
364-day
facility in January 2009 with no material changes to its terms
except for the rate of interest, which is the greater of
(i) the one-month LIBOR rate plus 2.00 percent or
(ii) the rate for AEMs offshore borrowings under its
committed credit facility plus 0.75 percent. Applicable
state regulatory commissions have approved the new facility
through December 31, 2009. There were no borrowings
outstanding under this facility at June 30, 2009.
Shelf
Registration
On March 23, 2009, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$450 million of capacity carried over from our prior shelf
registration statement filed with the SEC in December 2006.
As of June 30, 2009, we had $450 million of
availability remaining under the registration statement after
completing our Senior Notes Offering. However, due to certain
restrictions placed by one state regulatory commission on our
ability to issue securities under the registration statement, we
now have remaining and available for issuance a total of
approximately $300 million of equity securities and
$150 million of subordinated debt securities.
Debt
Covenants
In addition to the financial covenants described above, our debt
instruments contain various covenants that are usual and
customary for debt instruments of these types.
Additionally, our public debt indentures relating to our senior
notes and debentures, as well as our revolving credit
agreements, each contain a default provision that is triggered
if outstanding indebtedness arising out of any other credit
agreements in amounts ranging from in excess of $15 million
to in excess of $100 million becomes due by acceleration or
is not paid at maturity.
Further, AEMs credit agreement contains a cross-default
provision whereby AEM would be in default if it defaults on
other indebtedness, as defined, by at least $250 thousand in the
aggregate.
Finally, AEMs credit agreement contains a provision that
would limit the amount of credit available if Atmos Energy were
downgraded below an S&P rating of BBB and a Moodys
rating of Baa2. We have no other triggering events in our debt
instruments that are tied to changes in specified credit ratings
or stock price, nor have we entered into any transactions that
would require us to issue equity, based on our credit rating or
other triggering events.
We were in compliance with all of our debt covenants as of
June 30, 2009. If we were unable to comply with our debt
covenants, we would likely be required to repay our outstanding
balances on demand, provide additional collateral or take other
corrective actions.
25
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Basic and diluted earnings per share for the three and nine
months ended June 30, 2009 and 2008 are calculated as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share amounts)
|
|
|
Net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per share weighted
average common shares
|
|
|
91,338
|
|
|
|
89,648
|
|
|
|
90,940
|
|
|
|
89,281
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
616
|
|
|
|
|
|
|
|
611
|
|
|
|
557
|
|
Stock options
|
|
|
48
|
|
|
|
|
|
|
|
39
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per share weighted
average common shares
|
|
|
92,002
|
|
|
|
89,648
|
|
|
|
91,590
|
|
|
|
89,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share basic
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
$
|
2.28
|
|
|
$
|
2.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share diluted
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
$
|
2.26
|
|
|
$
|
1.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were approximately 33,000 and 132,000
out-of-the-money
stock options excluded from the computation of diluted earnings
per share for the three and nine months ended June 30, 2009.
There were approximately 557,000 restricted and other shares and
approximately 99,000 stock options that were excluded from the
calculation of diluted earnings per share for the three months
ended June 30, 2008 as their inclusion in the computation
would be anti-dilutive. There were no
out-of-the-money
stock options excluded from the computation of diluted earnings
per share for the three and nine months ended June 30, 2008
as their exercise price was less than the average market price
of the common stock during that period.
|
|
7.
|
Interim
Pension and Other Postretirement Benefit Plan
Information
|
The components of our net periodic pension cost for our pension
and other postretirement benefit plans for the three and nine
months ended June 30, 2009 and 2008 are presented in the
following table. Most of these costs are recoverable through our
gas distribution rates; however, a portion of these costs is
capitalized into our gas distribution rate base. The remaining
costs are recorded as a component of operation and maintenance
expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,703
|
|
|
$
|
3,879
|
|
|
$
|
2,946
|
|
|
$
|
3,342
|
|
Interest cost
|
|
|
7,554
|
|
|
|
6,736
|
|
|
|
3,520
|
|
|
|
2,912
|
|
Expected return on assets
|
|
|
(6,238
|
)
|
|
|
(6,311
|
)
|
|
|
(573
|
)
|
|
|
(715
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
378
|
|
|
|
377
|
|
Amortization of prior service cost
|
|
|
(183
|
)
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
Amortization of actuarial loss
|
|
|
955
|
|
|
|
1,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
5,791
|
|
|
$
|
6,059
|
|
|
$
|
6,271
|
|
|
$
|
5,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
11,109
|
|
|
$
|
11,635
|
|
|
$
|
8,838
|
|
|
$
|
10,024
|
|
Interest cost
|
|
|
22,662
|
|
|
|
20,208
|
|
|
|
10,560
|
|
|
|
8,736
|
|
Expected return on assets
|
|
|
(18,714
|
)
|
|
|
(18,932
|
)
|
|
|
(1,719
|
)
|
|
|
(2,145
|
)
|
Amortization of transition asset
|
|
|
|
|
|
|
|
|
|
|
1,134
|
|
|
|
1,133
|
|
Amortization of prior service cost
|
|
|
(549
|
)
|
|
|
(513
|
)
|
|
|
|
|
|
|
|
|
Amortization of actuarial loss
|
|
|
2,865
|
|
|
|
5,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
17,373
|
|
|
$
|
18,176
|
|
|
$
|
18,813
|
|
|
$
|
17,748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumptions used to develop our net periodic pension cost
for the three and nine months ended June 30, 2009 and 2008
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Discount rate
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
|
|
7.57
|
%
|
|
|
6.30
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.25
|
%
|
|
|
8.25
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
The discount rate used to compute the present value of a
plans liabilities generally is based on rates of
high-grade corporate bonds with maturities similar to the
average period over which the benefits will be paid. Generally,
our funding policy has been to contribute annually an amount in
accordance with the requirements of the Employee Retirement
Income Security Act of 1974. In accordance with the Pension
Protection Act of 2006 (PPA), we determined the funded status of
our plans as of January 1, 2009. In June 2009, we
contributed $21 million in cash to our pension plans to
achieve a desired level of funding while maximizing the tax
deductibility of this payment.
We contributed $8.2 million to our other post-retirement
benefit plans during the nine months ended June 30, 2009.
We expect to contribute a total of approximately
$11 million to these plans during fiscal 2009.
In April 2009, the FASB issued FSP
FAS 115-2
and
FAS 124-2,
Recognition and Presentation of
Other-Than-Temporary
Impairments. This FSP amends the
other-than-temporary
impairment guidance for debt securities and expands the
presentation and disclosure of
other-than-temporary
impairments on debt and equity securities in interim and annual
financial statements. This FSP does not amend existing
recognition and measurement guidance related to
other-than-temporary
impairments of equity securities.
For our Supplemental Executive Benefit Plans, we own equity
securities that are classified as
available-for-sale
securities. These securities are reported at market value with
unrealized gains and losses shown as a component of accumulated
other comprehensive income (loss). We regularly evaluate the
performance of these investments on a fund by fund basis for
impairment, taking into consideration the funds purpose,
volatility and current returns. If a determination is made that
a decline in fair value is other than temporary, the related
fund is written down to its estimated fair value and the
other-than-temporary
impairment is recognized in the income statement.
27
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Assets for the supplemental plans are held in separate rabbi
trusts and comprise the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Gross
|
|
|
|
|
|
|
Amortized
|
|
|
Unrealized
|
|
|
Unrealized
|
|
|
Fair
|
|
|
|
Cost
|
|
|
Gain
|
|
|
Loss
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
As of June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
25,824
|
|
|
$
|
286
|
|
|
$
|
|
|
|
$
|
26,110
|
|
Foreign equity mutual funds
|
|
|
4,047
|
|
|
|
|
|
|
|
|
|
|
|
4,047
|
|
Money market funds
|
|
|
8,699
|
|
|
|
|
|
|
|
|
|
|
|
8,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
38,570
|
|
|
$
|
286
|
|
|
$
|
|
|
|
$
|
38,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
31,041
|
|
|
$
|
1,625
|
|
|
$
|
(394
|
)
|
|
$
|
32,272
|
|
Foreign equity mutual funds
|
|
|
5,309
|
|
|
|
359
|
|
|
|
|
|
|
|
5,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,350
|
|
|
$
|
1,984
|
|
|
$
|
(394
|
)
|
|
$
|
37,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents interest and dividends on
available-for-sale
securities for the three and nine months ended June 30,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
June 30
|
|
|
Nine Months Ended June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Interest
|
|
$
|
8
|
|
|
$
|
|
|
|
$
|
8
|
|
|
$
|
|
|
Dividends
|
|
|
184
|
|
|
|
190
|
|
|
|
1,607
|
|
|
|
2,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest and dividends
|
|
$
|
192
|
|
|
$
|
190
|
|
|
$
|
1,615
|
|
|
$
|
2,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents realized gains and losses on
available-for-sale
securities for the three and nine months ended June 30,
2009 and 2008. The gross realized investment losses exclude
losses from
other-than-temporary
impairment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Three Months Ended June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Gross realized investment gains
|
|
$
|
|
|
|
$
|
51
|
|
|
$
|
|
|
|
$
|
97
|
|
Gross realized investment losses
|
|
|
|
|
|
|
(2
|
)
|
|
|
(129
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net realized gains (losses)
|
|
$
|
|
|
|
$
|
49
|
|
|
$
|
(129
|
)
|
|
$
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to the recent deterioration of the financial markets and the
uncertainty of a full recovery of these investments given the
current economic environment, we have recorded a
$3.3 million and $5.4 million noncash charge to impair
certain
available-for-sale
investments during the three and nine months ended June 30,
2009. As a result of these impairments, at June 30, 2009,
we did not maintain any investments that are in an unrealized
loss position.
|
|
8.
|
Commitments
and Contingencies
|
Litigation
and Environmental Matters
With respect to the specific litigation and
environmental-related matters or claims that were disclosed in
Note 12 to the financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30,
28
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008, there were no material changes in the status of such
litigation and environmental-related matters or claims during
the nine months ended June 30, 2009. We continue to believe
that the final outcome of such litigation and
environmental-related matters or claims will not have a material
adverse effect on our financial condition, results of operations
or cash flows.
In addition, we are involved in other litigation and
environmental-related matters or claims that arise in the
ordinary course of our business. While the ultimate results of
such litigation and response actions to such
environmental-related matters or claims cannot be predicted with
certainty, we believe the final outcome of such litigation and
response actions will not have a material adverse effect on our
financial condition, results of operations or cash flows.
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, 2009, AEM was committed to
purchase 83.0 Bcf within one year and 25.4 Bcf within
one to three years under indexed contracts. AEM is committed to
purchase 2.9 Bcf within one year under fixed price
contracts with prices ranging from $3.15 to $7.68 per Mcf.
Purchases under these contracts totaled $256.0 million and
$842.1 million for the three months ended June 30,
2009 and 2008 and $1,215.0 million and
$2,274.4 million for the nine months ended June 30,
2009 and 2008.
Our natural gas distribution divisions, except for our Mid-Tex
Division, maintain supply contracts with several vendors that
generally cover a period of up to one year. Commitments for
estimated base gas volumes are established under these contracts
on a monthly basis at contractually negotiated prices.
Commitments for incremental daily purchases are made as
necessary during the month in accordance with the terms of the
individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in this
service area which obligate it to purchase specified volumes at
market and fixed prices. The estimated commitments under these
contracts as of June 30, 2009 are as follows (in thousands):
|
|
|
|
|
2009
|
|
$
|
20,256
|
|
2010
|
|
|
120,481
|
|
2011
|
|
|
5,658
|
|
2012
|
|
|
7,302
|
|
2013
|
|
|
7,711
|
|
Thereafter
|
|
|
2,614
|
|
|
|
|
|
|
|
|
$
|
164,022
|
|
|
|
|
|
|
Regulatory
Matters
As previously described in Note 12 to the consolidated
financial statements in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008, in December
2007, the Company received data requests from the Division of
Investigations of the Office of Enforcement of the Federal
Energy Regulatory Commission (the Commission) in
connection with its investigation into possible violations of
the Commissions posting and competitive bidding
regulations for pre-arranged released firm capacity on natural
gas pipelines.
After responding to two sets of data requests received from the
Commission, the Commission agreed to allow us to conduct our own
internal investigation into compliance with the
Commissions rules. We have completed our internal
investigation and submitted the results to the Commission.
During our investigation, we identified certain transactions
that could possibly be considered non-compliant, and we continue
to fully
29
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
cooperate with the Commission as we work to resolve this matter.
We have accrued what we believe is an adequate amount for the
anticipated resolution of this proceeding. While the ultimate
resolution of this investigation cannot be predicted with
certainty, we believe that the final outcome will not have a
material adverse effect on our financial condition, results of
operations or cash flows.
As of June 30, 2009, rate cases were in progress in our
City of Dallas and Virginia service areas and annual rate filing
mechanisms were in progress in our City of Dallas and Amarillo
service areas. These regulatory proceedings are discussed in
further detail in Managements Discussion and
Analysis Recent Ratemaking Developments.
|
|
9.
|
Concentration
of Credit Risk
|
Information regarding our concentration of credit risk is
disclosed in Note 14 to the financial statements in our
Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. During the
nine months ended June 30, 2009, there were no material
changes in our concentration of credit risk.
Atmos Energy and our subsidiaries are engaged primarily in the
regulated natural gas distribution, transmission and storage
business as well as other nonregulated businesses. We distribute
natural gas through sales and transportation arrangements to
approximately 3.2 million residential, commercial, public
authority and industrial customers through our six regulated
natural gas distribution divisions, which cover service areas
located in 12 states. In addition, we transport natural gas
for others through our distribution system.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local distribution companies and industrial customers
primarily in the Midwest and Southeast. Additionally, we provide
natural gas transportation and storage services to certain of
our natural gas distribution operations and to third parties.
We operate the Company through the following four segments:
|
|
|
|
|
The natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations.
|
|
|
|
The regulated transmission and storage segment, which
includes the regulated pipeline and storage operations of the
Atmos Pipeline Texas Division.
|
|
|
|
The natural gas marketing segment, which includes a
variety of nonregulated natural gas management services.
|
|
|
|
The pipeline, storage and other segment, which includes
our nonregulated natural gas transmission and storage services.
|
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in differing regulatory environments.
Although our natural gas distribution segment operations are
geographically dispersed, they are reported as a single segment
as each natural gas distribution division has similar economic
characteristics. The accounting policies of the segments are the
same as those described in the summary of significant accounting
policies found in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. We evaluate
performance based on net income or loss of the respective
operating units.
30
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income statements for the three and nine month periods ended
June 30, 2009 and 2008 by segment are presented in the
following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
386,774
|
|
|
$
|
29,558
|
|
|
$
|
358,458
|
|
|
$
|
5,985
|
|
|
$
|
|
|
|
$
|
780,775
|
|
Intersegment revenues
|
|
|
211
|
|
|
|
19,787
|
|
|
|
95,046
|
|
|
|
2,241
|
|
|
|
(117,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
386,985
|
|
|
|
49,345
|
|
|
|
453,504
|
|
|
|
8,226
|
|
|
|
(117,285
|
)
|
|
|
780,775
|
|
Purchased gas cost
|
|
|
195,303
|
|
|
|
|
|
|
|
438,482
|
|
|
|
4,212
|
|
|
|
(116,862
|
)
|
|
|
521,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
191,682
|
|
|
|
49,345
|
|
|
|
15,022
|
|
|
|
4,014
|
|
|
|
(423
|
)
|
|
|
259,640
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
89,534
|
|
|
|
13,784
|
|
|
|
6,445
|
|
|
|
1,641
|
|
|
|
(509
|
)
|
|
|
110,895
|
|
Depreciation and amortization
|
|
|
47,928
|
|
|
|
5,066
|
|
|
|
392
|
|
|
|
795
|
|
|
|
|
|
|
|
54,181
|
|
Taxes, other than income
|
|
|
44,014
|
|
|
|
2,569
|
|
|
|
628
|
|
|
|
366
|
|
|
|
|
|
|
|
47,577
|
|
Asset impairments
|
|
|
2,823
|
|
|
|
370
|
|
|
|
90
|
|
|
|
21
|
|
|
|
|
|
|
|
3,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
184,299
|
|
|
|
21,789
|
|
|
|
7,555
|
|
|
|
2,823
|
|
|
|
(509
|
)
|
|
|
215,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,383
|
|
|
|
27,556
|
|
|
|
7,467
|
|
|
|
1,191
|
|
|
|
86
|
|
|
|
43,683
|
|
Miscellaneous income
|
|
|
2,167
|
|
|
|
615
|
|
|
|
71
|
|
|
|
2,319
|
|
|
|
(3,953
|
)
|
|
|
1,219
|
|
Interest charges
|
|
|
32,798
|
|
|
|
8,152
|
|
|
|
4,020
|
|
|
|
408
|
|
|
|
(3,867
|
)
|
|
|
41,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(23,248
|
)
|
|
|
20,019
|
|
|
|
3,518
|
|
|
|
3,102
|
|
|
|
|
|
|
|
3,391
|
|
Income tax expense (benefit)
|
|
|
(8,307
|
)
|
|
|
7,065
|
|
|
|
1,419
|
|
|
|
1,250
|
|
|
|
|
|
|
|
1,427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(14,941
|
)
|
|
$
|
12,954
|
|
|
$
|
2,099
|
|
|
$
|
1,852
|
|
|
$
|
|
|
|
$
|
1,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
86,861
|
|
|
$
|
28,216
|
|
|
$
|
82
|
|
|
$
|
5,837
|
|
|
$
|
|
|
|
$
|
120,996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
676,418
|
|
|
$
|
27,321
|
|
|
$
|
933,931
|
|
|
$
|
1,475
|
|
|
$
|
|
|
|
$
|
1,639,145
|
|
Intersegment revenues
|
|
|
221
|
|
|
|
18,965
|
|
|
|
255,791
|
|
|
|
2,405
|
|
|
|
(277,382
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
676,639
|
|
|
|
46,286
|
|
|
|
1,189,722
|
|
|
|
3,880
|
|
|
|
(277,382
|
)
|
|
|
1,639,145
|
|
Purchased gas cost
|
|
|
476,711
|
|
|
|
|
|
|
|
1,192,353
|
|
|
|
706
|
|
|
|
(276,847
|
)
|
|
|
1,392,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
199,928
|
|
|
|
46,286
|
|
|
|
(2,631
|
)
|
|
|
3,174
|
|
|
|
(535
|
)
|
|
|
246,222
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
95,853
|
|
|
|
17,042
|
|
|
|
4,433
|
|
|
|
1,115
|
|
|
|
(621
|
)
|
|
|
117,822
|
|
Depreciation and amortization
|
|
|
44,737
|
|
|
|
4,860
|
|
|
|
381
|
|
|
|
378
|
|
|
|
|
|
|
|
50,356
|
|
Taxes, other than income
|
|
|
54,141
|
|
|
|
2,493
|
|
|
|
391
|
|
|
|
310
|
|
|
|
|
|
|
|
57,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
194,731
|
|
|
|
24,395
|
|
|
|
5,205
|
|
|
|
1,803
|
|
|
|
(621
|
)
|
|
|
225,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
5,197
|
|
|
|
21,891
|
|
|
|
(7,836
|
)
|
|
|
1,371
|
|
|
|
86
|
|
|
|
20,709
|
|
Miscellaneous income
|
|
|
3,508
|
|
|
|
550
|
|
|
|
377
|
|
|
|
2,273
|
|
|
|
(5,108
|
)
|
|
|
1,600
|
|
Interest charges
|
|
|
28,504
|
|
|
|
6,606
|
|
|
|
2,850
|
|
|
|
532
|
|
|
|
(5,022
|
)
|
|
|
33,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(19,799
|
)
|
|
|
15,835
|
|
|
|
(10,309
|
)
|
|
|
3,112
|
|
|
|
|
|
|
|
(11,161
|
)
|
Income tax expense (benefit)
|
|
|
(7,421
|
)
|
|
|
5,570
|
|
|
|
(3,995
|
)
|
|
|
1,273
|
|
|
|
|
|
|
|
(4,573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,378
|
)
|
|
$
|
10,265
|
|
|
$
|
(6,314
|
)
|
|
$
|
1,839
|
|
|
$
|
|
|
|
$
|
(6,588
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
92,856
|
|
|
$
|
18,252
|
|
|
$
|
132
|
|
|
$
|
2,916
|
|
|
$
|
|
|
|
$
|
114,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
2,672,742
|
|
|
$
|
91,877
|
|
|
$
|
1,524,438
|
|
|
$
|
29,456
|
|
|
$
|
|
|
|
$
|
4,318,513
|
|
Intersegment revenues
|
|
|
631
|
|
|
|
71,384
|
|
|
|
425,219
|
|
|
|
7,490
|
|
|
|
(504,724
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,673,373
|
|
|
|
163,261
|
|
|
|
1,949,657
|
|
|
|
36,946
|
|
|
|
(504,724
|
)
|
|
|
4,318,513
|
|
Purchased gas cost
|
|
|
1,816,227
|
|
|
|
|
|
|
|
1,881,068
|
|
|
|
9,771
|
|
|
|
(503,456
|
)
|
|
|
3,203,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
857,146
|
|
|
|
163,261
|
|
|
|
68,589
|
|
|
|
27,175
|
|
|
|
(1,268
|
)
|
|
|
1,114,903
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
276,462
|
|
|
|
58,448
|
|
|
|
27,228
|
|
|
|
4,700
|
|
|
|
(1,526
|
)
|
|
|
365,312
|
|
Depreciation and amortization
|
|
|
142,608
|
|
|
|
15,027
|
|
|
|
1,189
|
|
|
|
1,933
|
|
|
|
|
|
|
|
160,757
|
|
Taxes, other than income
|
|
|
139,861
|
|
|
|
7,929
|
|
|
|
1,667
|
|
|
|
571
|
|
|
|
|
|
|
|
150,028
|
|
Asset impairments
|
|
|
4,599
|
|
|
|
602
|
|
|
|
146
|
|
|
|
35
|
|
|
|
|
|
|
|
5,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
563,530
|
|
|
|
82,006
|
|
|
|
30,230
|
|
|
|
7,239
|
|
|
|
(1,526
|
)
|
|
|
681,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
293,616
|
|
|
|
81,255
|
|
|
|
38,359
|
|
|
|
19,936
|
|
|
|
258
|
|
|
|
433,424
|
|
Miscellaneous income (expense)
|
|
|
6,123
|
|
|
|
1,713
|
|
|
|
490
|
|
|
|
6,540
|
|
|
|
(15,513
|
)
|
|
|
(647
|
)
|
Interest charges
|
|
|
94,506
|
|
|
|
23,580
|
|
|
|
11,383
|
|
|
|
1,821
|
|
|
|
(15,255
|
)
|
|
|
116,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
205,233
|
|
|
|
59,388
|
|
|
|
27,466
|
|
|
|
24,655
|
|
|
|
|
|
|
|
316,742
|
|
Income tax expense
|
|
|
68,465
|
|
|
|
19,308
|
|
|
|
11,444
|
|
|
|
10,595
|
|
|
|
|
|
|
|
109,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
136,768
|
|
|
$
|
40,080
|
|
|
$
|
16,022
|
|
|
$
|
14,060
|
|
|
$
|
|
|
|
$
|
206,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
260,482
|
|
|
$
|
61,579
|
|
|
$
|
199
|
|
|
$
|
20,066
|
|
|
$
|
|
|
|
$
|
342,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external parties
|
|
$
|
3,126,083
|
|
|
$
|
72,588
|
|
|
$
|
2,568,643
|
|
|
$
|
13,326
|
|
|
$
|
|
|
|
$
|
5,780,640
|
|
Intersegment revenues
|
|
|
589
|
|
|
|
70,184
|
|
|
|
590,449
|
|
|
|
7,303
|
|
|
|
(668,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,126,672
|
|
|
|
142,772
|
|
|
|
3,159,092
|
|
|
|
20,629
|
|
|
|
(668,525
|
)
|
|
|
5,780,640
|
|
Purchased gas cost
|
|
|
2,296,020
|
|
|
|
|
|
|
|
3,099,428
|
|
|
|
1,773
|
|
|
|
(666,835
|
)
|
|
|
4,730,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
830,652
|
|
|
|
142,772
|
|
|
|
59,664
|
|
|
|
18,856
|
|
|
|
(1,690
|
)
|
|
|
1,050,254
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
291,678
|
|
|
|
47,560
|
|
|
|
17,835
|
|
|
|
3,939
|
|
|
|
(1,948
|
)
|
|
|
359,064
|
|
Depreciation and amortization
|
|
|
130,699
|
|
|
|
14,683
|
|
|
|
1,142
|
|
|
|
1,135
|
|
|
|
|
|
|
|
147,659
|
|
Taxes, other than income
|
|
|
142,063
|
|
|
|
6,322
|
|
|
|
3,798
|
|
|
|
987
|
|
|
|
|
|
|
|
153,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
564,440
|
|
|
|
68,565
|
|
|
|
22,775
|
|
|
|
6,061
|
|
|
|
(1,948
|
)
|
|
|
659,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
266,212
|
|
|
|
74,207
|
|
|
|
36,889
|
|
|
|
12,795
|
|
|
|
258
|
|
|
|
390,361
|
|
Miscellaneous income
|
|
|
7,654
|
|
|
|
933
|
|
|
|
1,775
|
|
|
|
6,243
|
|
|
|
(13,631
|
)
|
|
|
2,974
|
|
Interest charges
|
|
|
88,802
|
|
|
|
20,453
|
|
|
|
6,166
|
|
|
|
1,755
|
|
|
|
(13,373
|
)
|
|
|
103,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
185,064
|
|
|
|
54,687
|
|
|
|
32,498
|
|
|
|
17,283
|
|
|
|
|
|
|
|
289,532
|
|
Income tax expense
|
|
|
71,622
|
|
|
|
19,351
|
|
|
|
12,933
|
|
|
|
6,877
|
|
|
|
|
|
|
|
110,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
113,442
|
|
|
$
|
35,336
|
|
|
$
|
19,565
|
|
|
$
|
10,406
|
|
|
$
|
|
|
|
$
|
178,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
266,840
|
|
|
$
|
40,334
|
|
|
$
|
201
|
|
|
$
|
5,503
|
|
|
$
|
|
|
|
$
|
312,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at June 30, 2009 and
September 30, 2008 by segment is presented in the following
tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,625,656
|
|
|
$
|
631,136
|
|
|
$
|
7,232
|
|
|
$
|
75,340
|
|
|
$
|
|
|
|
$
|
4,339,364
|
|
Investment in subsidiaries
|
|
|
526,941
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(524,845
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
39,276
|
|
|
|
|
|
|
|
76,111
|
|
|
|
10,348
|
|
|
|
|
|
|
|
125,735
|
|
Assets from risk management activities
|
|
|
1,233
|
|
|
|
|
|
|
|
30,696
|
|
|
|
3,835
|
|
|
|
(4,510
|
)
|
|
|
31,254
|
|
Other current assets
|
|
|
416,144
|
|
|
|
16,481
|
|
|
|
211,197
|
|
|
|
55,510
|
|
|
|
(60,309
|
)
|
|
|
639,023
|
|
Intercompany receivables
|
|
|
507,278
|
|
|
|
|
|
|
|
|
|
|
|
146,140
|
|
|
|
(653,418
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
963,931
|
|
|
|
16,481
|
|
|
|
318,004
|
|
|
|
215,833
|
|
|
|
(718,237
|
)
|
|
|
796,012
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
1,617
|
|
|
|
|
|
|
|
|
|
|
|
1,617
|
|
Goodwill
|
|
|
569,920
|
|
|
|
132,367
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
736,998
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
9,900
|
|
|
|
|
|
|
|
|
|
|
|
9,900
|
|
Deferred charges and other assets
|
|
|
181,945
|
|
|
|
9,959
|
|
|
|
1,045
|
|
|
|
19,190
|
|
|
|
|
|
|
|
212,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,868,393
|
|
|
$
|
789,943
|
|
|
$
|
359,984
|
|
|
$
|
320,792
|
|
|
$
|
(1,243,082
|
)
|
|
$
|
6,096,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,191,520
|
|
|
$
|
170,224
|
|
|
$
|
101,997
|
|
|
$
|
254,720
|
|
|
$
|
(526,941
|
)
|
|
$
|
2,191,520
|
|
Long-term debt
|
|
|
2,168,937
|
|
|
|
|
|
|
|
|
|
|
|
458
|
|
|
|
|
|
|
|
2,169,395
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,360,457
|
|
|
|
170,224
|
|
|
|
101,997
|
|
|
|
255,178
|
|
|
|
(526,941
|
)
|
|
|
4,360,915
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
|
|
|
|
|
131
|
|
Short-term debt
|
|
|
40,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,340
|
)
|
|
|
|
|
Liabilities from risk management activities
|
|
|
22,945
|
|
|
|
|
|
|
|
4,668
|
|
|
|
705
|
|
|
|
(4,510
|
)
|
|
|
23,808
|
|
Other current liabilities
|
|
|
427,859
|
|
|
|
8,270
|
|
|
|
151,717
|
|
|
|
50,274
|
|
|
|
(17,760
|
)
|
|
|
620,360
|
|
Intercompany payables
|
|
|
|
|
|
|
530,513
|
|
|
|
122,905
|
|
|
|
|
|
|
|
(653,418
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
491,144
|
|
|
|
538,783
|
|
|
|
279,290
|
|
|
|
51,110
|
|
|
|
(716,028
|
)
|
|
|
644,299
|
|
Deferred income taxes
|
|
|
444,621
|
|
|
|
76,837
|
|
|
|
(21,955
|
)
|
|
|
11,511
|
|
|
|
(113
|
)
|
|
|
510,901
|
|
Noncurrent liabilities from risk management activities
|
|
|
316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
316
|
|
Regulatory cost of removal obligation
|
|
|
322,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
322,529
|
|
Deferred credits and other liabilities
|
|
|
249,326
|
|
|
|
4,099
|
|
|
|
652
|
|
|
|
2,993
|
|
|
|
|
|
|
|
257,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,868,393
|
|
|
$
|
789,943
|
|
|
$
|
359,984
|
|
|
$
|
320,792
|
|
|
$
|
(1,243,082
|
)
|
|
$
|
6,096,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
ATMOS
ENERGY CORPORATION
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
|
Natural
|
|
|
Regulated
|
|
|
Natural
|
|
|
Pipeline,
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Transmission
|
|
|
Gas
|
|
|
Storage and
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
and Storage
|
|
|
Marketing
|
|
|
Other
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,483,556
|
|
|
$
|
585,160
|
|
|
$
|
7,520
|
|
|
$
|
60,623
|
|
|
$
|
|
|
|
$
|
4,136,859
|
|
Investment in subsidiaries
|
|
|
463,158
|
|
|
|
|
|
|
|
(2,096
|
)
|
|
|
|
|
|
|
(461,062
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
30,878
|
|
|
|
|
|
|
|
9,120
|
|
|
|
6,719
|
|
|
|
|
|
|
|
46,717
|
|
Assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
69,008
|
|
|
|
20,239
|
|
|
|
(20,956
|
)
|
|
|
68,291
|
|
Other current assets
|
|
|
774,933
|
|
|
|
18,396
|
|
|
|
411,648
|
|
|
|
56,791
|
|
|
|
(91,672
|
)
|
|
|
1,170,096
|
|
Intercompany receivables
|
|
|
578,833
|
|
|
|
|
|
|
|
|
|
|
|
135,795
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,384,644
|
|
|
|
18,396
|
|
|
|
489,776
|
|
|
|
219,544
|
|
|
|
(827,256
|
)
|
|
|
1,285,104
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
|
|
|
|
|
|
|
|
|
|
2,088
|
|
Goodwill
|
|
|
569,920
|
|
|
|
132,367
|
|
|
|
24,282
|
|
|
|
10,429
|
|
|
|
|
|
|
|
736,998
|
|
Noncurrent assets from risk management activities
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
|
|
|
|
|
|
|
|
|
|
5,473
|
|
Deferred charges and other assets
|
|
|
195,985
|
|
|
|
11,212
|
|
|
|
1,182
|
|
|
|
11,798
|
|
|
|
|
|
|
|
220,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
2,052,492
|
|
|
$
|
130,144
|
|
|
$
|
114,559
|
|
|
$
|
218,455
|
|
|
$
|
(463,158
|
)
|
|
$
|
2,052,492
|
|
Long-term debt
|
|
|
2,119,267
|
|
|
|
|
|
|
|
|
|
|
|
525
|
|
|
|
|
|
|
|
2,119,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
4,171,759
|
|
|
|
130,144
|
|
|
|
114,559
|
|
|
|
218,980
|
|
|
|
(463,158
|
)
|
|
|
4,172,284
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
785
|
|
|
|
|
|
|
|
785
|
|
Short-term debt
|
|
|
385,592
|
|
|
|
|
|
|
|
6,500
|
|
|
|
|
|
|
|
(41,550
|
)
|
|
|
350,542
|
|
Liabilities from risk management activities
|
|
|
58,566
|
|
|
|
|
|
|
|
20,688
|
|
|
|
616
|
|
|
|
(20,956
|
)
|
|
|
58,914
|
|
Other current liabilities
|
|
|
538,777
|
|
|
|
7,053
|
|
|
|
236,217
|
|
|
|
62,796
|
|
|
|
(47,997
|
)
|
|
|
796,846
|
|
Intercompany payables
|
|
|
|
|
|
|
543,384
|
|
|
|
171,244
|
|
|
|
|
|
|
|
(714,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
982,935
|
|
|
|
550,437
|
|
|
|
434,649
|
|
|
|
64,197
|
|
|
|
(825,131
|
)
|
|
|
1,207,087
|
|
Deferred income taxes
|
|
|
384,860
|
|
|
|
62,720
|
|
|
|
(21,936
|
)
|
|
|
15,687
|
|
|
|
(29
|
)
|
|
|
441,302
|
|
Noncurrent liabilities from risk management activities
|
|
|
5,111
|
|
|
|
|
|
|
|
258
|
|
|
|
|
|
|
|
|
|
|
|
5,369
|
|
Regulatory cost of removal obligation
|
|
|
298,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
298,645
|
|
Deferred credits and other liabilities
|
|
|
253,953
|
|
|
|
3,834
|
|
|
|
695
|
|
|
|
3,530
|
|
|
|
|
|
|
|
262,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6,097,263
|
|
|
$
|
747,135
|
|
|
$
|
528,225
|
|
|
$
|
302,394
|
|
|
$
|
(1,288,318
|
)
|
|
$
|
6,386,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of
Atmos Energy Corporation as of June 30, 2009, the related
condensed consolidated statements of income for the three-month
and nine-month periods ended June 30, 2009 and 2008, and
the condensed consolidated statements of cash flows for the
nine-month periods ended June 30, 2009 and 2008. These
financial statements are the responsibility of the
Companys management.
We conducted our review in accordance with the standards of the
Public Company Accounting Oversight Board (United States). A
review of interim financial information consists principally of
applying analytical procedures and making inquiries of persons
responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in
accordance with the standards of the Public Company Accounting
Oversight Board, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the condensed consolidated
financial statements referred to above for them to be in
conformity with U.S. generally accepted accounting
principles.
We have previously audited, in accordance with the standards of
the Public Company Accounting Oversight Board (United States),
the consolidated balance sheet of Atmos Energy Corporation as of
September 30, 2008, and the related consolidated statements
of income, shareholders equity, and cash flows for the
year then ended, not presented herein, and in our report dated
November 18, 2008, we expressed an unqualified opinion on
those consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated
balance sheet as of September 30, 2008, is fairly stated,
in all material respects, in relation to the consolidated
balance sheet from which it has been derived.
Dallas, Texas
August 5, 2009
37
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
INTRODUCTION
The following discussion should be read in conjunction with the
condensed consolidated financial statements in this Quarterly
Report on
Form 10-Q
and Managements Discussion and Analysis in our Annual
Report on
Form 10-K
for the year ended September 30, 2008.
Cautionary
Statement for the Purposes of the Safe Harbor under the Private
Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on
Form 10-Q
may contain forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical fact included in
this Report are forward-looking statements made in good faith by
us and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation
Reform Act of 1995. When used in this Report, or any other of
our documents or oral presentations, the words
anticipate, believe,
estimate, expect, forecast,
goal, intend, objective,
plan, projection, seek,
strategy or similar words are intended to identify
forward-looking statements. Such forward-looking statements are
subject to risks and uncertainties that could cause actual
results to differ materially from those expressed or implied in
the statements relating to our strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties, which are
discussed in more detail in our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008, include the
following: our ability to continue to access the credit markets
to satisfy our liquidity requirements; the impact of recent
adverse economic conditions on our customers; increased costs of
providing pension and postretirement health care benefits and
increased funding requirements; market risks beyond our control
affecting our risk management activities including market
liquidity, commodity price volatility, increasing interest rates
and counterparty creditworthiness; regulatory trends and
decisions, including the impact of rate proceedings before
various state regulatory commissions; increased federal
regulatory oversight and potential penalties; the impact of
environmental regulations on our business; the concentration of
our distribution, pipeline and storage operations in Texas;
adverse weather conditions; the effects of inflation and changes
in the availability and price of natural gas; the
capital-intensive nature of our gas distribution business;
increased competition from energy suppliers and alternative
forms of energy; the inherent hazards and risks involved in
operating our gas distribution business; natural disasters,
terrorist activities or other events; and other risks and
uncertainties discussed herein, all of which are difficult to
predict and many of which are beyond our control. Accordingly,
while we believe these forward-looking statements to be
reasonable, there can be no assurance that they will approximate
actual experience or that the expectations derived from them
will be realized. Further, we undertake no obligation to update
or revise any of our forward-looking statements whether as a
result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the
regulated natural gas distribution and transportation and
storage businesses as well as other nonregulated natural gas
businesses. We distribute natural gas through sales and
transportation arrangements to approximately 3.2 million
residential, commercial, public authority and industrial
customers throughout our six regulated natural gas distribution
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonregulated businesses, we primarily provide
natural gas management and marketing services to municipalities,
other local gas distribution companies and industrial customers
primarily in the Midwest and Southeast and natural gas
transportation and storage services to certain of our natural
gas distribution divisions and to third parties.
38
We operate the Company through the following four segments:
|
|
|
|
|
the natural gas distribution segment, which includes our
regulated natural gas distribution and related sales operations,
|
|
|
|
the regulated transmission and storage segment, which
includes the regulated pipeline and storage operations of the
Atmos Pipeline Texas Division,
|
|
|
|
the natural gas marketing segment, which includes a
variety of nonregulated natural gas management services and
|
|
|
|
the pipeline, storage and other segment, which is
comprised of our nonregulated natural gas gathering,
transmission and storage services.
|
CRITICAL
ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in
accordance with accounting principles generally accepted in the
United States. Preparation of these financial statements
requires us to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses
and the related disclosures of contingent assets and
liabilities. We based our estimates on historical experience and
various other assumptions that we believe to be reasonable under
the circumstances. On an ongoing basis, we evaluate our
estimates, including those related to risk management and
trading activities, the allowance for doubtful accounts, legal
and environmental accruals, insurance accruals, pension and
postretirement obligations, deferred income taxes and the
valuation of goodwill, indefinite-lived intangible assets and
other long-lived assets. Actual results may differ from such
estimates.
Our critical accounting policies used in the preparation of our
consolidated financial statements are described in our Annual
Report on
Form 10-K
for the fiscal year ended September 30, 2008 and include
the following:
|
|
|
|
|
Regulation
|
|
|
|
Revenue Recognition
|
|
|
|
Allowance for Doubtful Accounts
|
|
|
|
Derivatives and Hedging Activities
|
|
|
|
Impairment Assessments
|
|
|
|
Pension and Other Postretirement Plans
|
Our critical accounting policies are reviewed quarterly by the
Audit Committee. There were no significant changes to these
critical accounting policies during the nine months ended
June 30, 2009.
RESULTS
OF OPERATIONS
During the current fiscal year, several external factors have
impacted Atmos Energy, including but not limited to adverse
developments in the global and financial credit markets and the
unfavorable impact of the economic recession.
The tightening of the credit markets has made it more difficult
and more expensive for us to access the capital markets.
However, during the fiscal year, we have undertaken several
steps to improve our financial position. In March 2009, we
successfully completed an offering of $450 million
8.5% senior notes, and used most of the proceeds in April
2009 to redeem $400 million of senior notes that were
scheduled to mature in October 2009. Additionally, we enhanced
our liquidity sources in various ways. In October 2008, we
replaced our former $300 million
364-day
committed credit facility with a new
364-day
$212.5 million committed credit facility. Additionally, we
converted AEMs former $580 million uncommitted credit
facility to a
364-day
$375 million committed credit facility. This facility was
subsequently increased to $450 million in April 2009.
Finally, in April 2009 we replaced an expiring $18 million
unsecured committed credit facility
39
with a $25 million unsecured committed credit facility.
After entering into these new facilities, we currently have a
total of approximately $1.3 billion available to us under
four committed credit facilities. As a result of these
developments and our continued successful financial performance,
Standard & Poors Corporation (S&P) upgraded
our credit rating from BBB to BBB+ in December 2008 and
Moodys Investors Service (Moodys) upgraded the
credit rating on our senior long-term debt from Baa3 to Baa2 and
our commercial paper from
P-3 to
P-2 in May
2009. These ratings upgrades should improve our ability to
access the short-term capital markets to satisfy our liquidity
requirements on more economical terms in the future.
Challenging economic times have also impacted most of our
business segments. The impact of the economic downturn is most
apparent in a general decline in throughput. Our natural gas
distribution segment has experienced a
year-over-year
four percent decrease in consolidated throughput, primarily
associated with lower residential, commercial and industrial
consumption. Declines in the demand for natural gas as a result
of idle production and plant closures have contributed to a
seven percent
year-over-year
decrease in consolidated throughput in our regulated
transmission and storage segment and a five percent
year-over-year
decrease in consolidated sales volumes in our natural gas
marketing segment. However, recent improvements in rate design
in our natural gas distribution segment and the ability to earn
higher
per-unit
margins in our regulated transmission and storage and natural
gas marketing segments has more than offset the decline in
throughput and sales volumes. Additionally, reduced demand for
natural gas has resulted in lower natural gas prices, which has
contributed significantly to the increase in our operating cash
flow from $417 million for the nine months ended
June 30, 2008 to $825 million for the nine months
ended June 30, 2009.
The seasonality of our distribution business typically results
in a loss in our fiscal third quarter. However, we reported net
income of $2.0 million, or $0.02 per diluted share for the
three months ended June 30, 2009 compared with a net loss
of $6.6 million, or $0.07 per diluted share in the
prior-year quarter. The
quarter-over-quarter
improvement reflects higher gross profit in our regulated
transmission and storage and natural gas marketing segments
combined with lower consolidated operation and maintenance
expense, which more than offset lower natural gas distribution
margins and a $3.3 million charge to impair certain
available-for-sale
investments.
For the first nine months of fiscal 2009, net income increased
16 percent to $206.9 million, or $2.26 per diluted
share. Regulated operations contributed 85 percent of our
net income during this period with our nonregulated operations
contributing the remaining 15 percent. Results for the nine
months ended June 30, 2009 include the favorable impact of
a one-time tax benefit of $11.3 million, or $0.12 per
diluted share and the unfavorable impact of a $5.4 million
charge, or $0.04 per diluted share, to impair certain
available-for-sale
investments. Additionally, results for the nine-month period
ended June 30, 2009 reflect increased gross profit across
all of our business segments, partially offset by higher
depreciation expense, pipeline maintenance and employee costs
and interest expense.
The following table presents our consolidated financial
highlights for the three and nine months ended June 30,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
$
|
780,775
|
|
|
$
|
1,639,145
|
|
|
$
|
4,318,513
|
|
|
$
|
5,780,640
|
|
Gross profit
|
|
|
259,640
|
|
|
|
246,222
|
|
|
|
1,114,903
|
|
|
|
1,050,254
|
|
Operating expenses
|
|
|
215,957
|
|
|
|
225,513
|
|
|
|
681,479
|
|
|
|
659,893
|
|
Operating income
|
|
|
43,683
|
|
|
|
20,709
|
|
|
|
433,424
|
|
|
|
390,361
|
|
Miscellaneous income (expense)
|
|
|
1,219
|
|
|
|
1,600
|
|
|
|
(647
|
)
|
|
|
2,974
|
|
Interest charges
|
|
|
41,511
|
|
|
|
33,470
|
|
|
|
116,035
|
|
|
|
103,803
|
|
Income (loss) before income taxes
|
|
|
3,391
|
|
|
|
(11,161
|
)
|
|
|
316,742
|
|
|
|
289,532
|
|
Income tax expense (benefit)
|
|
|
1,427
|
|
|
|
(4,573
|
)
|
|
|
109,812
|
|
|
|
110,783
|
|
Net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
Diluted net income (loss) per share
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
$
|
2.26
|
|
|
$
|
1.99
|
|
40
Our consolidated net income (loss) during the three and nine
months ended June 30, 2009 and 2008 was earned in each of
our business segments as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
(14,941
|
)
|
|
$
|
(12,378
|
)
|
|
$
|
(2,563
|
)
|
Regulated transmission and storage segment
|
|
|
12,954
|
|
|
|
10,265
|
|
|
|
2,689
|
|
Natural gas marketing segment
|
|
|
2,099
|
|
|
|
(6,314
|
)
|
|
|
8,413
|
|
Pipeline, storage and other segment
|
|
|
1,852
|
|
|
|
1,839
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
$
|
8,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Natural gas distribution segment
|
|
$
|
136,768
|
|
|
$
|
113,442
|
|
|
$
|
23,326
|
|
Regulated transmission and storage segment
|
|
|
40,080
|
|
|
|
35,336
|
|
|
|
4,744
|
|
Natural gas marketing segment
|
|
|
16,022
|
|
|
|
19,565
|
|
|
|
(3,543
|
)
|
Pipeline, storage and other segment
|
|
|
14,060
|
|
|
|
10,406
|
|
|
|
3,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
|
$
|
28,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables segregate our consolidated net income
(loss) and diluted earnings per share between our regulated and
nonregulated operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
(1,987
|
)
|
|
$
|
(2,113
|
)
|
|
$
|
126
|
|
Nonregulated operations
|
|
|
3,951
|
|
|
|
(4,475
|
)
|
|
|
8,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income (loss)
|
|
$
|
1,964
|
|
|
$
|
(6,588
|
)
|
|
$
|
8,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
(0.02
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
|
|
Diluted EPS from nonregulated operations
|
|
|
0.04
|
|
|
|
(0.05
|
)
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
0.02
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, except per share data)
|
|
|
Regulated operations
|
|
$
|
176,848
|
|
|
$
|
148,778
|
|
|
$
|
28,070
|
|
Nonregulated operations
|
|
|
30,082
|
|
|
|
29,971
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated net income
|
|
$
|
206,930
|
|
|
$
|
178,749
|
|
|
$
|
28,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS from regulated operations
|
|
$
|
1.93
|
|
|
$
|
1.66
|
|
|
$
|
0.27
|
|
Diluted EPS from nonregulated operations
|
|
|
0.33
|
|
|
|
0.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated diluted EPS
|
|
$
|
2.26
|
|
|
$
|
1.99
|
|
|
$
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
Three
Months Ended June 30, 2009 compared with Three Months Ended
June 30, 2008
Natural
Gas Distribution Segment
The primary factors that impact the results of our natural gas
distribution operations are our ability to earn our authorized
rates of return, the cost of natural gas, competitive factors in
the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based
primarily on our ability to improve the rate design in our
various ratemaking jurisdictions by reducing or eliminating
regulatory lag and, ultimately, separating the recovery of our
approved margins from customer usage patterns. Improving rate
design is a long-term process and is further complicated by the
fact that we operate in multiple rate jurisdictions.
Seasonal weather patterns can also affect our natural gas
distribution operations. However, the effect of weather that is
above or below normal is substantially offset through weather
normalization adjustments, known as WNA, which has been approved
by state regulatory commissions for approximately
90 percent of our residential and commercial meters in the
following states for the following time periods:
|
|
|
Georgia
|
|
October May
|
Kansas
|
|
October May
|
Kentucky
|
|
November April
|
Louisiana
|
|
December March
|
Mississippi
|
|
November April
|
Tennessee
|
|
November April
|
Texas: Mid-Tex
|
|
November April
|
Texas: West Texas
|
|
October May
|
Virginia
|
|
January December
|
Our natural gas distribution operations are also affected by the
cost of natural gas. The cost of gas is passed through to our
customers without markup. Therefore, increases in the cost of
gas are offset by a corresponding increase in revenues.
Accordingly, we believe gross profit is a better indicator of
our financial performance than revenues.
Gross profit in our Texas and Mississippi service areas includes
franchise fees and gross receipts taxes, which are calculated as
a percentage of revenue (inclusive of gas costs). Therefore, the
amount of these taxes included in revenues is influenced by the
cost of gas and the level of gas sales volumes. We record the
associated tax expense as a component of taxes, other than
income. Although changes in these revenue-related taxes arising
from changes in gas costs affect gross profit, over time the
impact of these timing differences is generally offset within
operating income. Prior to January 1, 2009, timing
differences existed between the recognition of revenue for
franchise fees collected from our customers and the recognition
of expense of franchise taxes. These timing differences had a
significant temporary effect on operating income in periods with
volatile gas prices, particularly in our Mid-Tex Division.
Beginning January 1, 2009, changes in our franchise fee
agreements in our Mid-Tex Division became effective which should
significantly reduce the impact of this timing difference on a
prospective basis. However, this timing difference will still be
present for gross receipts taxes.
Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt expense and
may require us to increase borrowings under our credit
facilities resulting in higher interest expense. Finally, higher
gas costs, as well as competitive factors in the industry and
general economic conditions may cause customers to conserve or
use alternative energy sources.
42
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the three months ended June 30,
2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
191,682
|
|
|
$
|
199,928
|
|
|
$
|
(8,246
|
)
|
Operating expenses
|
|
|
184,299
|
|
|
|
194,731
|
|
|
|
(10,432
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,383
|
|
|
|
5,197
|
|
|
|
2,186
|
|
Miscellaneous income
|
|
|
2,167
|
|
|
|
3,508
|
|
|
|
(1,341
|
)
|
Interest charges
|
|
|
32,798
|
|
|
|
28,504
|
|
|
|
4,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(23,248
|
)
|
|
|
(19,799
|
)
|
|
|
(3,449
|
)
|
Income tax benefit
|
|
|
(8,307
|
)
|
|
|
(7,421
|
)
|
|
|
(886
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(14,941
|
)
|
|
$
|
(12,378
|
)
|
|
$
|
(2,563
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
40,081
|
|
|
|
41,357
|
|
|
|
(1,276
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
29,597
|
|
|
|
32,126
|
|
|
|
(2,529
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
69,678
|
|
|
|
73,483
|
|
|
|
(3,805
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.43
|
|
|
$
|
0.03
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
4.87
|
|
|
$
|
11.53
|
|
|
$
|
(6.66
|
)
|
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the three months ended June 30, 2009 and 2008. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
(3,598
|
)
|
|
$
|
(3,043
|
)
|
|
$
|
(555
|
)
|
Kentucky/Mid-States
|
|
|
2,931
|
|
|
|
5,757
|
|
|
|
(2,826
|
)
|
Louisiana
|
|
|
5,459
|
|
|
|
5,086
|
|
|
|
373
|
|
West Texas
|
|
|
1,010
|
|
|
|
(563
|
)
|
|
|
1,573
|
|
Mississippi
|
|
|
(585
|
)
|
|
|
(946
|
)
|
|
|
361
|
|
Colorado-Kansas
|
|
|
1,247
|
|
|
|
542
|
|
|
|
705
|
|
Other
|
|
|
919
|
|
|
|
(1,636
|
)
|
|
|
2,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,383
|
|
|
$
|
5,197
|
|
|
$
|
2,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $8.2 million decrease in natural gas distribution gross
profit primarily reflects a net $5.4 million decrease in
margins in the Mid-Tex Division. This reduction in margins was
primarily due to rate design changes implemented in November
2008 that decreased the monthly base charge and increased the
volumetric charge for most of the Mid-Tex Divisions
customers. This change results in higher gross profit during the
winter heating season and lower gross profit in the summer
months. The current year period also reflects a
$3.3 million increase in rate adjustments primarily in
Georgia, Kansas, Louisiana and West Texas. The
43
decrease in gross profit also reflects a $3.5 million
decrease as a result of a five percent decrease in distribution
throughput, primarily associated with lower residential,
commercial and industrial consumption. Finally, service revenue
and late charges, which are based on the customers
outstanding balance, decreased $1.3 million due to the
lower cost of natural gas in the current-year period.
Partially offsetting these decreases was an increase of
approximately $1.3 million in revenue-related taxes in the
current-year quarter compared to the prior-year quarter
primarily due to the timing change in franchise fees in our
Mid-Tex Division. This increase was combined with a
$9.5 million
quarter-over-quarter
decrease in the associated franchise and state gross receipts
tax expense recorded as a component of taxes, other than income,
resulting in a $10.8 million increase in operating income
when compared with the prior-year quarter.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income, and asset
impairments decreased $10.4 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, decreased $4.9 million, primarily due to
lower legal and other administrative costs. These decreases were
partially offset by a $2.8 million noncash charge to impair
certain
available-for-sale
investments as the Company believed the fair value of these
investments would not recover within a reasonable period of time.
Depreciation and amortization expense increased
$3.2 million for the third quarter of fiscal 2009 compared
with third quarter of fiscal 2008. The increase primarily was
attributable to additional assets placed in service during the
current-year period.
Interest charges allocated to the natural gas distribution
segment increased $4.3 million due to the effect of the
Companys March 2009 issuance of $450 million
8.50% senior notes to repay $400 million
4.00% senior notes in April 2009.
Recent
Ratemaking Developments
Significant ratemaking developments that occurred during the
nine months ended June 30, 2009 are discussed below. The
amounts described below represent the operating income that was
requested or received in each rate filing, which may not
necessarily reflect the stated amount referenced in the final
order, as certain operating costs may have changed as a result
of a commissions final ruling.
Annual
Rate Filing Mechanisms
In March 2009, the Mid-Tex Division filed its second Rate Review
Mechanism (RRM) with the Settled Cities. The filing requested an
increase in annual operating income of $9.7 million for the
Settled Cities. The Mid-Tex Division and representatives of the
Settled Cities reached an agreement to increase annual operating
income by $2.0 million, which will be implemented in rates
beginning in August 2009. Beginning in November 2008, rates were
implemented from our first RRM filing with the Settled Cities,
which resulted in an increase in annual operating income on a
system-wide basis of approximately $27.3 million. The
impact to the Mid-Tex Division for the Settled Cities was
approximately $21.8 million.
In April 2009, the West Texas Division filed its second RRM with
the West Texas Cities. The filing requested an increase in
annual operating income of $11.1 million. The West Texas
Division and representatives of the West Texas Cities reached an
agreement to increase annual operating income $7.8 million,
which will be implemented in rates beginning in August 2009.
Beginning in November 2008, rates were implemented from our
first RRM with the West Texas Cities, which resulted in an
increase in operating income of $4.5 million, of which
$3.9 million is being collected over a
91/2
month period.
In April 2009, the City of Lubbock approved an RRM tariff
similar to the RRM tariff utilized by the West Texas Cities. The
West Texas Division filed its first RRM with the City of Lubbock
on April 15, 2009. The filing requested an increase in
annual operating income of $3.5 million. The City of
Lubbock is currently reviewing the filing and a final
determination is expected in October 2009.
44
In June 2009, the City of Amarillo approved an RRM tariff
similar to the RRM tariff utilized by the West Texas Cities. The
West Texas Division filed its first RRM with the City of
Amarillo on June 17, 2009. The filing requested an annual
increase in operating income of $2.3 million. The City of
Amarillo is currently reviewing the filing and a final
determination is expected in October 2009.
In December 2008, the Louisiana Division filed its
TransLa annual rate stabilization clause with the Louisiana
Public Service Commission (LPSC) for the test year ended
September 30, 2008. The filing resulted in an annual
increase in operating income of $0.6 million and was
implemented in April 2009.
In April 2009, the Louisiana Division filed its LGS annual rate
stabilization clause with the LPSC. The filing was for the test
year ended December 31, 2008. The filing resulted in an
annual increase in operating income of $3.3 million and was
implemented in July 2009.
In September 2008, we filed our Mississippi stable rate filing
with the Mississippi Public Service Commission (MPSC) requesting
an increase in annual operating income of $3.5 million. In
January 2009, we withdrew this request after we were unable to
reach a mutually agreeable settlement with the MPSC.
GRIP
Filings
In May 2008, the Mid-Tex Division made a GRIP filing seeking a
$10.3 million increase on a system-wide basis. However,
this filing was only applicable to the City of Dallas and the
Mid-Tex environs and sought a $1.8 million increase for
customers in those service areas. Rates were approved for this
filing in December 2008 and were implemented in January 2009.
However, in April 2009, the City of Dallas challenged the
legality of the implementation of the GRIP rates, which the
Company is contesting in the District Courts of Dallas and
Travis Counties.
In March 2009, the Mid-Tex Division made a GRIP filing seeking
an $18.7 million increase on a system-wide basis. However,
this filing is applicable to the City of Dallas only and seeks a
$2.7 million increase for customers in the City of Dallas.
The City of Dallas denied this GRIP filing in June 2009 and the
Mid-Tex Division has appealed this action to the Railroad
Commission of Texas (RRC).
Any rate increases granted from these GRIP filings will be in
effect until such time that they are superseded by the statement
of intent filed with the City of Dallas discussed below.
Rate Case
Filings
In October 2008, our Kentucky/Mid-States Division filed a rate
case with the Tennessee Regulatory Authority seeking an increase
in annual operating income of $6.3 million. In January
2009, the Consumer Advocate and Protection Division recommended
a decrease in rates of $3.7 million. In March 2009, a
unanimous stipulation was filed and approved in the case. The
parties agreed to an increase in annual operating income of
$2.5 million with a stated return on equity of
10.3 percent. The increase in rates was implemented in
April 2009.
In November 2008, the Mid-Tex Division filed a statement of
intent to increase annual operating income for customers within
the City of Dallas by $9.1 million. The City of Dallas
suspended the filing in December 2008 and denied the increase in
March 2009. The Mid-Tex Division has appealed the filing and in
April 2009 we requested an increase in annual operating income
of $7.5 million and concurrently filed for a statement of
intent to increase annual operating income $1.3 million
applicable to the Mid-Tex unincorporated areas. The City of
Dallas has proposed a reduction of rates of $28.9 million
to annual operating income system-wide, or approximately
$5.8 million for the City of Dallas and environs customers.
On August 4, 2009, the Mid-Tex Division filed a rebuttal
revising the requested increase in annual operating income to
$6.6 million for the City of Dallas and $1.1 million
for the Mid-Tex unincorporated areas. A hearing is scheduled
with the RRC in August 2009 and a final ruling is expected in
November 2009. If the statement of intent applicable to the City
of Dallas is approved by the RRC, the new rates implemented
could supersede the City of Dallas GRIP rates discussed above.
45
In April 2009, the Kentucky/Mid-States Division filed an
expedited rate case with the Virginia State Corporation
Commission seeking an increase in annual operating income of
$1.7 million. Interim rates were implemented subject to
refund on May 1, 2009. The application is currently in
discovery with a final determination expected in October 2009.
In July 2009, the Colorado/Kansas Division filed a rate case
with the Colorado Public Service Commission seeking an increase
in annual operating income of $3.8 million effective in
August 2009. A procedural schedule has not been established;
however the Commission is expected to suspend the filing.
Other
Ratemaking Activity
In May 2007, our Mid-Tex Division filed for a
36-month gas
contract review filing. This filing was mandated by prior RRC
orders and related to the prudency of gas purchases made from
November 2003 through October 2006, which total approximately
$2.7 billion. The intervening parties recommended
disallowances ranging from $58 million to $89 million.
A hearing was held at the RRC in September 2008. In December
2008, a proposal for decision was issued by the Hearing Examiner
recommending no gas cost disallowance. In February 2009, the RRC
approved the Hearing Examiners recommendation to disallow
no gas costs.
In March 2009, the RRC established a procedural schedule to
examine the
36-month gas
contract review process. Briefs were filed in April 2009 and the
Hearing Examiner issued a proposal for decision in June 2009
which recommended the elimination of the
36-month gas
contract review process. The RRC has not taken any action on the
proposed final order.
Regulated
Transmission and Storage Segment
Our regulated transmission and storage segment consists of the
regulated pipeline and storage operations of the Atmos
Pipeline Texas Division. The Atmos
Pipeline Texas Division transports natural gas to
our Mid-Tex Division and third parties and manages five
underground storage reservoirs in Texas. We also provide
ancillary services customary in the pipeline industry including
parking and lending arrangements and sales of inventory on hand.
Similar to our natural gas distribution segment, our regulated
transmission and storage segment is impacted by seasonal weather
patterns, competitive factors in the energy industry and
economic conditions in our service areas. Further, as the Atmos
Pipeline Texas Division operations supply all of the
natural gas for our Mid-Tex Division, the results of this
segment are highly dependent upon the natural gas requirements
of the Mid-Tex Division. Finally, as a regulated pipeline, the
operations of the Atmos Pipeline Texas Division may
be impacted by the timing of when costs and expenses are
incurred and when these costs and expenses are recovered through
its tariffs.
46
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the three months ended
June 30, 2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
19,507
|
|
|
$
|
18,761
|
|
|
$
|
746
|
|
Third-party transportation
|
|
|
24,285
|
|
|
|
22,485
|
|
|
|
1,800
|
|
Storage and park and lend services
|
|
|
3,137
|
|
|
|
2,387
|
|
|
|
750
|
|
Other
|
|
|
2,416
|
|
|
|
2,653
|
|
|
|
(237
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
49,345
|
|
|
|
46,286
|
|
|
|
3,059
|
|
Operating expenses
|
|
|
21,789
|
|
|
|
24,395
|
|
|
|
(2,606
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
27,556
|
|
|
|
21,891
|
|
|
|
5,665
|
|
Miscellaneous income
|
|
|
615
|
|
|
|
550
|
|
|
|
65
|
|
Interest charges
|
|
|
8,152
|
|
|
|
6,606
|
|
|
|
1,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
20,019
|
|
|
|
15,835
|
|
|
|
4,184
|
|
Income tax expense
|
|
|
7,065
|
|
|
|
5,570
|
|
|
|
1,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
12,954
|
|
|
$
|
10,265
|
|
|
$
|
2,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
169,641
|
|
|
|
181,112
|
|
|
|
(11,471
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
141,556
|
|
|
|
152,450
|
|
|
|
(10,894
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $3.1 million increase in gross profit was attributable
primarily to a $3.5 million increase from higher
demand-based fees. The improvement in gross profit also reflects
a $1.1 million increase due to our GRIP filings. These
increases were partially offset by a $0.7 million decrease
arising from a seven percent decrease in city-gate, electrical
generation, Barnett Shale and HUB deliveries.
Operating expenses decreased $2.6 million primarily due to
a decrease in pipeline maintenance costs during the current-year
quarter.
Recent
Ratemaking Developments
In February 2009, the Atmos Pipeline Texas Division
made a GRIP filing seeking an increase in annual operating
income of $6.3 million. The filing was approved by the RRC
and a final order was issued in April 2009.
Natural
Gas Marketing Segment
Our natural gas marketing activities are conducted through Atmos
Energy Marketing, LLC (AEM). AEM aggregates and purchases gas
supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request, including
furnishing natural gas supplies at fixed and market-based
prices, contract negotiation and administration, load
forecasting, gas storage acquisition and management services,
transportation services, peaking sales and balancing services,
capacity utilization strategies and gas price hedging through
the use of financial instruments. As a result, our revenues
arise from the types of commercial transactions we have
structured with our customers and include the value we extract
by optimizing the storage and transportation capacity we own or
control as well as revenues received for services we deliver.
Our asset optimization activities seek to maximize the economic
value associated with the storage and transportation capacity we
own or control. We attempt to meet this objective by engaging in
natural gas storage transactions in which we seek to find and
profit from the pricing differences that occur over time. We
purchase physical natural gas and then sell financial
instruments at advantageous prices to lock in a gross
47
profit margin. We also seek to participate in transactions in
which we combine the natural gas commodity and transportation
costs to minimize our costs incurred to serve our customers by
identifying the lowest cost alternative within the natural gas
supplies, transportation and markets to which we have access.
Through the use of transportation and storage services and
financial instruments, we also seek to capture gross profit
margin through the arbitrage of pricing differences that exist
in various locations and by recognizing pricing differences that
occur over time.
AEM continually manages its net physical position to attempt to
increase in the future the potential economic gross profit that
was created when the original transaction was executed.
Therefore, AEM may subsequently change its originally scheduled
storage injection and withdrawal plans from one time period to
another based on market conditions and recognize any associated
gains or losses at that time. If AEM elects to accelerate the
withdrawal of physical gas, it will execute new financial
instruments to economically hedge the original financial
instruments. If AEM elects to defer the withdrawal of gas, it
will reset its financial instruments by settling the original
financial instruments and executing new financial instruments to
correspond to the revised withdrawal schedule.
We use financial instruments, designated as fair value hedges,
to hedge our natural gas inventory used in our natural gas
marketing storage activities. These financial instruments are
marked to market each month based upon the NYMEX price with
changes in fair value recognized as unrealized gains and losses
in the period of change. The hedged natural gas inventory is
marked to market at the end of each month based on the Gas Daily
index with changes in fair value recognized as unrealized gains
and losses in the period of change. Changes in the spreads
between the forward natural gas prices used to value the
financial hedges designated against our physical inventory and
the market (spot) prices used to value our physical storage
result in unrealized margins until the underlying physical gas
is withdrawn and the related financial instruments are settled.
Once the gas is withdrawn and the financial instruments are
settled, the previously unrealized margins associated with these
net positions are realized.
AEM also uses financial instruments to capture additional
storage arbitrage opportunities that may arise after the
execution of the original physical inventory hedge and to
attempt to insulate and protect the economic value within its
asset optimization activities. Changes in fair value associated
with these financial instruments are recognized as a component
of unrealized margins until they are settled.
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the three months ended June 30, 2009
and 2008 are presented below. Gross profit margin consists
primarily of margins earned from the delivery of gas and related
services requested by our customers and margins earned from
asset optimization activities, which are derived from the
utilization of our proprietary and managed third-party storage
and transportation assets to capture favorable arbitrage spreads
through natural gas trading activities.
Unrealized margins represent the unrealized gains or losses on
our net physical gas position and the related financial
instruments used to manage commodity price risk as described
above. These margins fluctuate based upon changes in the spreads
between the physical (spot) and forward natural gas prices.
Generally, if the physical/financial spread narrows, we will
record unrealized gains or lower unrealized losses. If the
physical/financial spread widens, we will record unrealized
losses or lower unrealized gains. The magnitude of the
48
unrealized gains and losses is also contingent upon the levels
of our net physical position at the end of the reporting period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
16,598
|
|
|
$
|
11,231
|
|
|
$
|
5,367
|
|
Asset optimization
|
|
|
(14,580
|
)
|
|
|
(37,551
|
)
|
|
|
22,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,018
|
|
|
|
(26,320
|
)
|
|
|
28,338
|
|
Unrealized margins
|
|
|
13,004
|
|
|
|
23,689
|
|
|
|
(10,685
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
15,022
|
|
|
|
(2,631
|
)
|
|
|
17,653
|
|
Operating expenses
|
|
|
7,555
|
|
|
|
5,205
|
|
|
|
2,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,467
|
|
|
|
(7,836
|
)
|
|
|
15,303
|
|
Miscellaneous income
|
|
|
71
|
|
|
|
377
|
|
|
|
(306
|
)
|
Interest charges
|
|
|
4,020
|
|
|
|
2,850
|
|
|
|
1,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
3,518
|
|
|
|
(10,309
|
)
|
|
|
13,827
|
|
Income tax expense (benefit)
|
|
|
1,419
|
|
|
|
(3,995
|
)
|
|
|
5,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,099
|
|
|
$
|
(6,314
|
)
|
|
$
|
8,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
103,146
|
|
|
|
103,403
|
|
|
|
(257
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
84,162
|
|
|
|
82,122
|
|
|
|
2,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
20.0
|
|
|
|
17.5
|
|
|
|
2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $17.7 million increase in our natural gas marketing
segments gross profit was driven primarily by a
$23.0 million increase in asset optimization margins. The
increase was primarily the result of a decrease in losses
realized on financial settlements during the current quarter
when compared to the prior-year quarter. Settlements during both
years were primarily related to the deferral of storage
withdrawals as AEM had elected to reset the corresponding
financial instruments to future periods to increase the
potential gross profit it could realize from its asset
optimization activities. The reduction in realized losses was
caused by greater price volatility in the prior-year period
which had a greater impact on the settlement of financial
instruments used to hedge our physical storage.
The increase in asset optimization margins was partially offset
by a $10.7 million decrease in unrealized margins. This
decrease reflects lower volatility during the current quarter
compared with the prior-year quarter between current cash prices
used to value our physical inventory and future natural gas
prices, which influence the prices used to value the financial
instruments used to hedge our physical inventory.
In addition, delivered gas margins increased $5.4 million
compared with the prior-year quarter largely attributable to a
48 percent increase in gross
per-unit
margins on similar gross sales volumes period over period as a
result of greater basis opportunities in certain market areas
and successful contract renewals.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income taxes, and asset
impairments increased $2.4 million primarily due to an
increase in legal and other administrative costs.
Economic
Gross Profit
AEM monitors the impact of its asset optimization efforts by
estimating the gross profit, before associated storage fees,
that it captured through the purchase and sale of physical
natural gas and the execution of the associated financial
instruments. This economic gross profit, combined with the
effect of the future reversal of
49
unrealized gains or losses currently recognized in the income
statement is referred to as the potential gross
profit.(1)
The following table presents AEMs economic gross profit
and its potential gross profit at June 30, 2009,
March 31, 2009, December 31, 2008, September 30,
2008 and June 30, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated Net
|
|
|
|
|
|
|
Net Physical
|
|
|
Economic
|
|
|
Unrealized
|
|
|
Potential Gross
|
|
Period Ending
|
|
Position
|
|
|
Gross Profit
|
|
|
Gain
|
|
|
Profit(1)
|
|
|
|
(Bcf)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
June 30, 2009
|
|
|
20.0
|
|
|
$
|
42.0
|
|
|
$
|
16.7
|
|
|
$
|
25.3
|
|
March 31, 2009
|
|
|
21.9
|
|
|
$
|
33.4
|
|
|
$
|
2.4
|
|
|
$
|
31.0
|
|
December 31, 2008
|
|
|
16.3
|
|
|
$
|
20.7
|
|
|
$
|
4.8
|
|
|
$
|
15.9
|
|
September 30, 2008
|
|
|
8.0
|
|
|
$
|
48.5
|
|
|
$
|
36.4
|
|
|
$
|
12.1
|
|
June 30, 2008
|
|
|
17.5
|
|
|
$
|
48.2
|
|
|
$
|
34.3
|
|
|
$
|
13.9
|
|
|
|
|
(1) |
|
Potential gross profit represents the increase in AEMs
gross profit in future periods if its optimization efforts are
executed as planned. This amount does not include storage and
other operating expenses and increased income taxes that will be
incurred to realize this amount. Therefore, it does not
represent an estimated increase in future net income. There is
no assurance that the economic gross profit or the potential
gross profit will be fully realized in the future. We consider
this measure a non-GAAP financial measure as it is calculated
using both forward-looking storage injection/withdrawal and
hedge settlement estimates and historical financial information.
This measure is presented because we believe it provides our
investors a more comprehensive view of our asset optimization
efforts and thus a better understanding of these activities than
would be presented by GAAP measures alone. |
As of June 30, 2009, based upon AEMs planned
inventory withdrawal schedule and associated planned settlement
of financial instruments, the economic gross profit was
$42.0 million. This amount will be reduced by
$16.7 million of net unrealized gains recorded in the
financial statements as of June 30, 2009 that will reverse
when the inventory is withdrawn and the accompanying financial
instruments are settled. Therefore, the potential gross profit
associated with these positions was $25.3 million at
June 30, 2009.
During the nine months ended June 30, 2009, AEM increased
its potential gross profit by $13.2 million to
$25.3 million. In the first quarter, AEM withdrew gas and
substantially realized the associated potential gross profit
reported as of September 30, 2008. Since that time, as a
result of falling current cash prices, AEM has been deferring
storage withdrawals and has been a net injector of gas into
storage to increase the potential gross profit it could realize
in future periods from its asset optimization activities. As a
result of these activities, AEM has increased its net physical
position by 12.0 Bcf since September 30, 2008.
However, the captured spreads on these positions have been lower
than those captured as of September 30, 2008, resulting in
a lower economic gross profit compared to that time. This
decrease from September 2008 to June 2009 was partially offset
by lower unrealized gains associated with these positions
primarily due to lower current cash prices and lower volatility
between cash and future prices.
The economic gross profit is based upon planned storage
injection and withdrawal schedules and its realization is
contingent upon the execution of this plan, weather and other
execution factors. Since AEM actively manages and optimizes its
portfolio to attempt to enhance the future profitability of its
storage position, it may change its scheduled storage injection
and withdrawal plans from one time period to another based on
market conditions. Therefore, we cannot ensure that the economic
gross profit or the potential gross profit calculated as of
June 30, 2009 will be fully realized in the future nor can
we predict in what time periods such realization may occur.
Further, if we experience operational or other issues which
limit our ability to optimally manage our stored gas positions,
our earnings could be adversely impacted. Assuming AEM fully
executes its plan in place on June 30, 2009, without
encountering operational or other issues, we anticipate that
approximately $15.9 million of the economic gross profit as
of June 30, 2009 will be recognized in fiscal 2009 with the
remaining $26.1 million expected to be recognized during
the first six months of fiscal 2010.
50
Pipeline,
Storage and Other Segment
Our pipeline, storage and other segment consists primarily of
the operations of Atmos Pipeline and Storage, LLC (APS). APS
owns and operates a 21 mile pipeline located in New
Orleans, Louisiana. This pipeline is primarily used to aggregate
gas supply for our regulated natural gas distribution division
in Louisiana and for AEM, but also provides limited third party
transportation services.
APS also engages in asset optimization activities whereby it
seeks to maximize the economic value associated with the storage
and transportation capacity it owns or controls. Certain of
these arrangements are asset management plans with regulated
affiliates of the Company which have been approved by applicable
state regulatory commissions. Generally, these asset management
plans require APS to share with our regulated customers a
portion of the profits earned from these arrangements.
Further, APS owns or has an interest in underground storage
fields in Kentucky and Louisiana that are used to reduce the
need of our natural gas distribution divisions to contract for
pipeline capacity to meet customer demand during peak periods.
Finally, APS manages our natural gas gathering operations, which
were limited in nature as of June 30, 2009.
Results for this segment are impacted primarily by seasonal
weather patterns and volatility in the natural gas markets.
Additionally, this segments results include an unrealized
component as APS hedges its risk associated with its asset
optimization activities.
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the three months ended June 30, 2009
and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Asset optimization
|
|
$
|
1,051
|
|
|
$
|
(484
|
)
|
|
$
|
1,535
|
|
Storage and transportation services
|
|
|
3,470
|
|
|
|
3,464
|
|
|
|
6
|
|
Other
|
|
|
737
|
|
|
|
592
|
|
|
|
145
|
|
Unrealized margins
|
|
|
(1,244
|
)
|
|
|
(398
|
)
|
|
|
(846
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
4,014
|
|
|
|
3,174
|
|
|
|
840
|
|
Operating expenses
|
|
|
2,823
|
|
|
|
1,803
|
|
|
|
1,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
1,191
|
|
|
|
1,371
|
|
|
|
(180
|
)
|
Miscellaneous income
|
|
|
2,319
|
|
|
|
2,273
|
|
|
|
46
|
|
Interest charges
|
|
|
408
|
|
|
|
532
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
3,102
|
|
|
|
3,112
|
|
|
|
(10
|
)
|
Income tax expense
|
|
|
1,250
|
|
|
|
1,273
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,852
|
|
|
$
|
1,839
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit from our pipeline, storage and other segment
increased $0.8 million primarily due to a $1.5 million
increase in asset optimization margins resulting from larger
basis gains earned from utilizing controlled pipeline capacity.
These increases were partially offset by a $0.8 million
decrease in unrealized margins associated with our asset
optimization activities due to a widening of the spreads between
current cash prices and forward natural gas prices.
Operating expenses for the three months ended June 30, 2009
increased $1.0 million primarily due to increased employee
costs and higher depreciation expense, which was largely
attributable to additional assets placed in service during the
current-year period.
51
Nine
Months Ended June 30, 2009 compared with Nine Months Ended
June 30, 2008
Natural
Gas Distribution Segment
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
distribution segment for the nine months ended June 30,
2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Gross profit
|
|
$
|
857,146
|
|
|
$
|
830,652
|
|
|
$
|
26,494
|
|
Operating expenses
|
|
|
563,530
|
|
|
|
564,440
|
|
|
|
(910
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
293,616
|
|
|
|
266,212
|
|
|
|
27,404
|
|
Miscellaneous income
|
|
|
6,123
|
|
|
|
7,654
|
|
|
|
(1,531
|
)
|
Interest charges
|
|
|
94,506
|
|
|
|
88,802
|
|
|
|
5,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
205,233
|
|
|
|
185,064
|
|
|
|
20,169
|
|
Income tax expense
|
|
|
68,465
|
|
|
|
71,622
|
|
|
|
(3,157
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
136,768
|
|
|
$
|
113,442
|
|
|
$
|
23,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution sales volumes
MMcf
|
|
|
253,087
|
|
|
|
261,692
|
|
|
|
(8,605
|
)
|
Consolidated natural gas distribution transportation
volumes MMcf
|
|
|
98,994
|
|
|
|
105,605
|
|
|
|
(6,611
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated natural gas distribution
throughput MMcf
|
|
|
352,081
|
|
|
|
367,297
|
|
|
|
(15,216
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas distribution average transportation
revenue per Mcf
|
|
$
|
0.46
|
|
|
$
|
0.44
|
|
|
$
|
0.02
|
|
Consolidated natural gas distribution average cost of gas per
Mcf sold
|
|
$
|
7.18
|
|
|
$
|
8.77
|
|
|
$
|
(1.59
|
)
|
The following table shows our operating income by natural gas
distribution division, in order of total customers served, for
the nine months ended June 30, 2009 and 2008. The
presentation of our natural gas distribution operating income is
included for financial reporting purposes and may not be
appropriate for ratemaking purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Mid-Tex
|
|
$
|
129,454
|
|
|
$
|
119,661
|
|
|
$
|
9,793
|
|
Kentucky/Mid-States
|
|
|
49,360
|
|
|
|
49,800
|
|
|
|
(440
|
)
|
Louisiana
|
|
|
39,825
|
|
|
|
36,254
|
|
|
|
3,571
|
|
West Texas
|
|
|
23,829
|
|
|
|
13,332
|
|
|
|
10,497
|
|
Mississippi
|
|
|
24,621
|
|
|
|
23,397
|
|
|
|
1,224
|
|
Colorado-Kansas
|
|
|
23,471
|
|
|
|
22,766
|
|
|
|
705
|
|
Other
|
|
|
3,056
|
|
|
|
1,002
|
|
|
|
2,054
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
293,616
|
|
|
$
|
266,212
|
|
|
$
|
27,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52
The $26.5 million increase in natural gas distribution
gross profit primarily reflects a net $35.1 million
increase in rates. The net increase in rates was attributable
primarily to the Mid-Tex Division, which increased
$22.4 million as a result of the implementation of its 2008
Rate Review Mechanism (RRM) filing with all incorporated cities
in the division other than the City of Dallas (the Settled
Cities) and rate adjustments for customers in the City of
Dallas. The current year period also reflects a
$12.7 million increase in rate adjustments primarily in
Georgia, Kansas, Louisiana and West Texas. The increase in gross
profit also reflects the reversal of a $7.0 million
uncollectible gas cost accrual recorded in a prior year and a
$7.8 million increase attributable to a non-recurring
update to our estimate for gas delivered to customers but not
yet billed to reflect changes in base rates in several of our
jurisdictions recorded in the fiscal first quarter. These
increases in gross profit were partially offset by an
$18.8 million decrease as a result of a four percent
decrease in distribution throughput primarily associated with
lower residential, commercial and industrial consumption and
warmer weather in our Colorado service area, which does not have
weather-normalized rates.
Partially offsetting these increases was a decrease of
approximately $8.0 million in revenue-related taxes
primarily due to lower revenues, on which the tax is calculated,
in the current-year period compared to the prior-year period.
This decrease, partially offset by a $2.2 million
period-over-period
decrease in the associated franchise and state gross receipts
tax expense recorded as a component of taxes other than income,
resulted in a $5.8 million decrease in operating income
when compared with the prior-year period.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income, and asset
impairments decreased $0.9 million.
Operation and maintenance expense, excluding the provision for
doubtful accounts, decreased $11.3 million, primarily due
to lower legal, fuel and other administrative costs. These
decreases were partially offset by a $4.6 million noncash
charge to impair certain
available-for-sale
investments as the Company believed the fair value of these
investments would not recover within a reasonable period of time.
Depreciation and amortization expense increased
$11.9 million for the current-year period compared with
nine months ended June 30, 2008. The increase primarily was
attributable to additional assets placed in service during the
current-year period.
Results for the prior-year period also included a
$1.2 million gain on the sale of irrigation assets in our
West Texas Division.
Interest charges allocated to the natural gas distribution
segment increased $5.7 million primarily due to the effect
of the Companys March 2009 issuance of $450 million
8.50% senior notes to repay $400 million
4.00% senior notes in April 2009. In addition, higher
average short-term debt balances, interest rates and commitment
fees were experienced during the current-year period compared to
the prior-year period.
Results for the current-year period include a $10.5 million
tax benefit associated with updating the rates used to determine
our deferred taxes.
53
Regulated
Transmission and Storage Segment
Review of
Financial and Operating Results
Financial and operational highlights for our regulated
transmission and storage segment for the nine months ended
June 30, 2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Mid-Tex transportation
|
|
$
|
70,920
|
|
|
$
|
69,409
|
|
|
$
|
1,511
|
|
Third-party transportation
|
|
|
73,497
|
|
|
|
58,946
|
|
|
|
14,551
|
|
Storage and park and lend services
|
|
|
8,151
|
|
|
|
6,288
|
|
|
|
1,863
|
|
Other
|
|
|
10,693
|
|
|
|
8,129
|
|
|
|
2,564
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
163,261
|
|
|
|
142,772
|
|
|
|
20,489
|
|
Operating expenses
|
|
|
82,006
|
|
|
|
68,565
|
|
|
|
13,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
81,255
|
|
|
|
74,207
|
|
|
|
7,048
|
|
Miscellaneous income
|
|
|
1,713
|
|
|
|
933
|
|
|
|
780
|
|
Interest charges
|
|
|
23,580
|
|
|
|
20,453
|
|
|
|
3,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
59,388
|
|
|
|
54,687
|
|
|
|
4,701
|
|
Income tax expense
|
|
|
19,308
|
|
|
|
19,351
|
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
40,080
|
|
|
$
|
35,336
|
|
|
$
|
4,744
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross pipeline transportation volumes MMcf
|
|
|
555,169
|
|
|
|
593,452
|
|
|
|
(38,283
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pipeline transportation volumes MMcf
|
|
|
400,699
|
|
|
|
429,758
|
|
|
|
(29,059
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $20.5 million increase in gross profit was attributable
primarily to an $11.0 million increase from higher
demand-based fees and a $7.5 million increase resulting
from higher transportation fees on through-system deliveries due
to market conditions. The improvement in gross profit also
reflects a $3.8 million increase due to our GRIP filings
and a $2.9 million gain on the sale of excess gas during
the current-year period. These increases were partially offset
by a $4.2 million decrease associated with a seven percent
decrease in city-gate, electrical generation, Barnett Shale and
HUB deliveries.
Operating expenses increased $13.4 million primarily due to
increased employee and pipeline maintenance costs.
Results for the current-year period also include a
$1.7 million tax benefit associated with updating the rates
used to determine our deferred taxes.
54
Natural
Gas Marketing Segment
Review of
Financial and Operating Results
Financial and operational highlights for our natural gas
marketing segment for the nine months ended June 30, 2009
and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Realized margins
|
|
|
|
|
|
|
|
|
|
|
|
|
Delivered gas
|
|
$
|
58,316
|
|
|
$
|
55,599
|
|
|
$
|
2,717
|
|
Asset optimization
|
|
|
20,286
|
|
|
|
(10,339
|
)
|
|
|
30,625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78,602
|
|
|
|
45,260
|
|
|
|
33,342
|
|
Unrealized margins
|
|
|
(10,013
|
)
|
|
|
14,404
|
|
|
|
(24,417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
68,589
|
|
|
|
59,664
|
|
|
|
8,925
|
|
Operating expenses
|
|
|
30,230
|
|
|
|
22,775
|
|
|
|
7,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
38,359
|
|
|
|
36,889
|
|
|
|
1,470
|
|
Miscellaneous income
|
|
|
490
|
|
|
|
1,775
|
|
|
|
(1,285
|
)
|
Interest charges
|
|
|
11,383
|
|
|
|
6,166
|
|
|
|
5,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
27,466
|
|
|
|
32,498
|
|
|
|
(5,032
|
)
|
Income tax expense
|
|
|
11,444
|
|
|
|
12,933
|
|
|
|
(1,489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,022
|
|
|
$
|
19,565
|
|
|
$
|
(3,543
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross natural gas marketing sales volumes MMcf
|
|
|
336,870
|
|
|
|
348,789
|
|
|
|
(11,919
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated natural gas marketing sales volumes MMcf
|
|
|
282,443
|
|
|
|
298,351
|
|
|
|
(15,908
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
20.0
|
|
|
|
17.5
|
|
|
|
2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $8.9 million increase in our natural gas marketing
segments gross profit was driven primarily by a
$30.6 million increase in asset optimization margins.
During the first quarter of fiscal 2009, AEM withdrew physical
storage inventory and realized the spreads it had captured
during fiscal 2008 as a result of deferring storage withdrawals
and increasing the spreads associated with those physical
positions. These gains were partially offset by margin losses
incurred in the second and third fiscal quarters as a result of
deferring storage withdrawals and injecting gas into storage. In
the prior-year period, AEM deferred storage withdrawals from the
first quarter into the second quarter, and recognized the
storage withdrawal gains during the second quarter of fiscal
2008.
The increase in asset optimization margins was partially offset
by a $24.4 million decrease in unrealized margins. This
decrease reflects lower volatility during the current year
compared with the prior-year period between current cash prices
used to value our physical inventory and future natural gas
prices, which influence the prices used to value the financial
instruments used to hedge our physical inventory.
Additionally, realized delivered gas margins increased by
$2.7 million. The increase was largely attributable to a
nine percent increase in gross
per-unit
margins as a result of improved basis spreads in certain market
areas where we were able to better optimize transportation
assets and successful contract renewals, partially offset by a
three percent decrease in gross sales volumes primarily
associated with lower industrial demand due to the current
economic climate.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense, taxes, other than income taxes, and asset
impairments increased $7.5 million primarily due to an
increase in legal and other administrative costs partially
offset by the absence in the current year of $2.4 million
related to tax matters incurred in the prior-year period.
55
Pipeline,
Storage and Other Segment
Review of
Financial and Operating Results
Financial and operational highlights for our pipeline, storage
and other segment for the nine months ended June 30, 2009
and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
(In thousands)
|
|
|
Asset optimization
|
|
$
|
21,675
|
|
|
$
|
5,890
|
|
|
$
|
15,785
|
|
Storage and transportation services
|
|
|
10,097
|
|
|
|
10,487
|
|
|
|
(390
|
)
|
Other
|
|
|
2,076
|
|
|
|
2,432
|
|
|
|
(356
|
)
|
Unrealized margins
|
|
|
(6,673
|
)
|
|
|
47
|
|
|
|
(6,720
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
27,175
|
|
|
|
18,856
|
|
|
|
8,319
|
|
Operating expenses
|
|
|
7,239
|
|
|
|
6,061
|
|
|
|
1,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
19,936
|
|
|
|
12,795
|
|
|
|
7,141
|
|
Miscellaneous income
|
|
|
6,540
|
|
|
|
6,243
|
|
|
|
297
|
|
Interest charges
|
|
|
1,821
|
|
|
|
1,755
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
24,655
|
|
|
|
17,283
|
|
|
|
7,372
|
|
Income tax expense
|
|
|
10,595
|
|
|
|
6,877
|
|
|
|
3,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
14,060
|
|
|
$
|
10,406
|
|
|
$
|
3,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit from our pipeline, storage and other segment
increased $8.3 million primarily due to a
$15.8 million increase in asset optimization margins as a
result of larger realized gains from the settlement of financial
positions associated with storage and trading activities, basis
gains earned from utilizing controlled pipeline capacity and
higher margins earned under asset management plans during the
current-year period compared with the prior-year period. These
increases were partially offset by a $6.7 million decrease
in unrealized margins associated with our asset optimization
activities due to a widening of the spreads between current cash
prices and forward natural gas prices.
Operating expenses for the nine months ended June 30, 2009
increased $1.2 million primarily due to increased employee
costs and higher depreciation expense which was largely
attributable to additional assets placed in service during the
current-year period.
Liquidity
and Capital Resources
The liquidity required to fund our working capital, capital
expenditures and other cash needs is provided from a variety of
sources including internally generated funds and borrowings
under our commercial paper program and bank credit facilities.
Additionally, we have various uncommitted trade credit lines
with our gas suppliers that we utilize to purchase natural gas
on a monthly basis. Finally, from time to time, we raise funds
from the public debt and equity capital markets to fund our
liquidity needs.
The primary means we use to fund our working capital needs and
growth is to utilize internally generated funds and to access
the commercial paper markets. Recent adverse developments in
global financial and credit markets have made it more difficult
and more expensive for the Company to access the short-term
capital markets, including the commercial paper market, to
satisfy our liquidity requirements. Consequently, during the
first quarter, we experienced higher than normal borrowings
under our five-year credit facility used to backstop our
commercial paper program in lieu of commercial paper borrowings
to fund our working capital needs. However, subsequent to the
end of the first quarter, credit market conditions improved,
both as to availability and interest rates, and we have been
able to access the commercial paper markets on more reasonably
economical terms. At June 30, 2009, there were no
borrowings or commercial paper outstanding under this facility
and $566.7 million was available.
56
On March 26, 2009, we closed our offering of
$450 million of 8.50% senior notes due 2019. Most of
the net proceeds of approximately $446 million were used to
redeem our $400 million 4.00% unsecured senior notes on
April 30, 2009, prior to their October 2009 maturity. In
connection with the repayment of the $400 million 4.00%
unsecured senior notes, we paid a $6.6 million call premium
in accordance with the terms of the senior notes and accrued
interest of approximately $0.6 million. The remaining net
proceeds were used for general corporate purposes.
During the nine months ended June 30, 2009, we enhanced our
liquidity sources in various ways. In October 2008, we replaced
our former $300 million
364-day
committed credit facility with a new facility that will allow
borrowings up to $212.5 million and expires in October
2009. We are currently evaluating alternatives to replace this
facility and believe we will successfully replace this facility
on reasonably economical terms.
In December 2008, we converted AEMs former
$580 million uncommitted credit facility to a
$375 million committed credit facility that will expire in
December 2009. Effective April 1, 2009, we exercised the
accordion feature of this facility to increase the credit
available under the facility to $450 million. In addition,
we replaced our $18 million unsecured committed credit
facility that expired in March 2009 with a $25 million
unsecured facility effective April 1, 2009. As a result of
executing these new agreements, we have a total of approximately
$1.3 billion available to us under four committed credit
facilities. As of June 30, 2009, the amount available to us
under our credit facilities, net of outstanding letters of
credit, was approximately $905 million.
We believe the liquidity provided by our senior notes and
committed credit facilities, combined with our operating cash
flows, will be sufficient to fund our working capital needs and
capital expenditure program for the remainder of fiscal 2009.
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 and working capital changes,
particularly within our natural gas distribution segment
resulting from the price of natural gas and the timing of
customer collections, payments for natural gas purchases and
deferred gas cost recoveries.
For the nine months ended June 30, 2009, we generated
operating cash flow of $824.6 million from operating
activities compared with $417.4 million for the nine months
ended June 30, 2008. Period over period, the
$407.2 million increase was attributable primarily to the
favorable impact on our working capital due to the decline in
natural gas prices in the current year compared to the
prior-year period which increased operating cash flow by
$251.1 million. The increase in operating cash flow was
also positively impacted by $99.9 million due to lower cash
margin requirements related to our natural gas marketing
financial instruments and by $49.0 million due to the
favorable timing in the recovery of gas costs during the current
year. Partially offsetting these increases in operating cash
flows was the $21.0 million contribution to our pension
plans in the current year.
Cash
flows from investing activities
In recent years, a substantial portion of our cash resources has
been used to fund growth projects, our ongoing construction
program and improvements to information technology systems. Our
ongoing construction program enables us to provide natural gas
distribution services to our existing customer base, expand our
natural gas distribution services into new markets, enhance the
integrity of our pipelines and, more recently,
57
expand our intrastate pipeline network. In executing our current
rate strategy, we are directing discretionary capital spending
to jurisdictions that permit us to earn a timely return on our
investment. Currently, our Mid-Tex, Louisiana, Mississippi and
West Texas natural gas distribution divisions and our Atmos
Pipeline Texas Division have rate designs that
provide the opportunity to include in their rate base approved
capital costs on a periodic basis without being required to file
a rate case.
Capital expenditures for fiscal 2009 are expected to range from
$500 million to $515 million. For the nine months
ended June 30, 2009, capital expenditures were
$342.3 million compared with $312.9 million for the
nine months ended June 30, 2008. The increase in capital
spending primarily reflects spending for a nonregulated growth
project and the construction of a pipeline extension in our
regulated operations.
Cash
flows from financing activities
For the nine months ended June 30, 2009, our financing
activities used $397.2 million compared with
$114.4 million in the prior-year period. Our significant
financing activities for the nine months ended June 30,
2009 and 2008 are summarized as follows:
|
|
|
|
|
On March 26, 2009, we issued $450 million of
8.50% senior notes due 2019. The effective interest rate of
this offering, inclusive of all debt issue costs, was
8.74 percent. After giving effect to the settlement of our
$450 million Treasury lock agreement on March 23,
2009, the effective rate on these senior notes was reduced to
8.69 percent. Most of the net proceeds of approximately
$446 million were used to repay our $400 million
unsecured 4.00% senior notes on April 30, 2009.
|
|
|
|
During the nine months ended June 30, 2009, we decreased
our borrowings by a net $366.4 million under our short-term
credit facilities compared with $35.7 million in the
prior-year period. The reduction in the net borrowings reflects
the combination of increased cash flows and lower natural gas
prices during the current year.
|
|
|
|
We repaid $407.3 million of long-term debt during the nine
months ended June 30, 2009 compared with $9.9 million
during the nine months ended June 30, 2008. The increase in
payments in the current year reflects the redemption of our
$400 million unsecured 4.00% senior notes discussed
above.
|
|
|
|
During the nine months ended June 30, 2009, we paid
$90.9 million in cash dividends compared with
$87.8 million for the nine months ended June 30, 2008.
The increase in dividends paid over the prior-year period
reflects the increase in our dividend rate from $0.975 per share
during the nine months ended June 30, 2008 to $0.99 per
share during the nine months ended June 30, 2009 combined
with new share issuances under our various equity plans.
|
|
|
|
During the nine months ended June 30, 2009, we issued
0.9 million shares of common stock under our various equity
plans, which generated net proceeds of $19.9 million. In
addition, we issued 0.5 million shares of common stock
under our 1998 Long-Term Incentive Plan.
|
The following table summarizes our share issuances for the nine
months ended June 30, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
Direct Stock Purchase Plan
|
|
|
319,732
|
|
|
|
294,071
|
|
Retirement Savings Plan and Trust
|
|
|
484,111
|
|
|
|
410,350
|
|
1998 Long-Term Incentive Plan
|
|
|
613,314
|
|
|
|
538,100
|
|
Outside Directors
Stock-for-Fee
Plan
|
|
|
2,294
|
|
|
|
2,399
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
1,419,451
|
|
|
|
1,244,920
|
|
|
|
|
|
|
|
|
|
|
58
Credit
Facilities
Our short-term borrowing requirements are affected by the
seasonal nature of the natural gas business. Changes in the
price of natural gas and the amount of natural gas we need to
supply to meet our customers needs could significantly
affect our borrowing requirements. However, our short-term
borrowings reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a
combination of a $566.7 million commercial paper program
and four committed revolving credit facilities with third-party
lenders that provide approximately $1.3 billion of working
capital funding. As of June 30, 2009, the amount available
to us under our credit facilities, net of outstanding letters of
credit, was approximately $905 million. These facilities
are described in further detail in Note 5 to the unaudited
condensed consolidated financial statements.
Shelf
Registration
On March 23, 2009, we filed a registration statement with
the Securities and Exchange Commission (SEC) to issue, from time
to time, up to $900 million in common stock
and/or debt
securities available for issuance, including approximately
$450 million of capacity carried over from our prior shelf
registration statement filed with the SEC in December 2006.
Immediately following the filing of the registration statement,
we issued $450 million of 8.50% senior notes due 2019
under the registration statement. Most of the net proceeds of
approximately $446 million were used to repay our
$400 million unsecured 4.00% senior notes on
April 30, 2009.
As of June 30, 2009, we had $450 million of
availability remaining under the registration statement.
However, due to certain restrictions placed by one state
regulatory commission on our ability to issue securities under
the registration statement, we now have remaining and available
for issuance a total of approximately $300 million of
equity securities and $150 million of subordinated debt
securities.
Credit
Ratings
Our credit ratings directly affect our ability to obtain
short-term and long-term financing, in addition to the cost of
such financing. In determining our credit ratings, the rating
agencies consider a number of quantitative factors, including
debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and
pension liabilities and funding status. In addition, the rating
agencies consider qualitative factors such as consistency of our
earnings over time, the quality of our management and business
strategy, the risks associated with our regulated and
nonregulated businesses and the regulatory structures that
govern our rates in the states where we operate.
Our debt is rated by three rating agencies: Standard &
Poors Corporation (S&P), Moodys Investors
Service (Moodys) and Fitch Ratings, Ltd. (Fitch). In
December 2008, S&P upgraded our senior long-term debt
credit rating from BBB to BBB+ and changed our rating outlook
from positive to stable. S&P cited improved financial
performance and rate case decisions that have increased cash
flow as the key drivers for the upgrade. In January 2009,
Moodys changed our rating outlook from stable to positive.
In May 2009, Moodys upgraded the credit rating on our
senior long-term debt from Baa3 to Baa2 and on our commercial
paper from
P-3 to
P-2 and
changed our rating outlook from positive to stable. Moodys
stated that the key drivers for the upgrade were the completion
of a major debt refinancing and the Company improving its
alternate liquidity resources while maintaining solid financial
performance. Fitch still maintains its stable outlook. Our
current debt ratings are all considered investment grade and are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
|
Moodys
|
|
|
Fitch
|
|
|
Unsecured senior long-term debt
|
|
|
BBB+
|
|
|
|
Baa2
|
|
|
|
BBB+
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-2
|
|
|
|
F-2
|
|
A significant degradation in our operating performance or a
significant reduction in our liquidity caused by more limited
access to the private and public credit markets as a result of
the recent adverse global financial and credit conditions could
trigger a negative change in our ratings outlook or even a
reduction in
59
our credit ratings by the three credit rating agencies. This
would mean more limited access to the private and public credit
markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold
securities. The highest investment grade credit rating for
S&P is AAA, Moodys is Aaa and Fitch is AAA. The
lowest investment grade credit rating for S&P is BBB-,
Moodys is Baa3 and Fitch is BBB-. Our credit ratings may
be revised or withdrawn at any time by the rating agencies, and
each rating should be evaluated independent of any other rating.
There can be no assurance that a rating will remain in effect
for any given period of time or that a rating will not be
lowered, or withdrawn entirely, by a rating agency if, in its
judgment, circumstances so warrant.
Debt
Covenants
We were in compliance with all of our debt covenants as of
June 30, 2009. Our debt covenants are described in greater
detail in Note 5 to the unaudited condensed consolidated
financial statements.
Capitalization
The following table presents our capitalization inclusive of
short-term debt and the current portion of long-term debt as of
June 30, 2009, September 30, 2008 and June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
September 30, 2008
|
|
|
June 30, 2008
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
|
|
|
|
|
%
|
|
$
|
350,542
|
|
|
|
7.7
|
%
|
|
$
|
113,257
|
|
|
|
2.6
|
%
|
Long-term debt
|
|
|
2,169,526
|
|
|
|
49.7
|
%
|
|
|
2,120,577
|
|
|
|
46.9
|
%
|
|
|
2,120,788
|
|
|
|
48.9
|
%
|
Shareholders equity
|
|
|
2,191,520
|
|
|
|
50.3
|
%
|
|
|
2,052,492
|
|
|
|
45.4
|
%
|
|
|
2,105,407
|
|
|
|
48.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,361,046
|
|
|
|
100.0
|
%
|
|
$
|
4,523,611
|
|
|
|
100.0
|
%
|
|
$
|
4,339,452
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt as a percentage of total capitalization, including
short-term debt, was 49.7 percent at June 30, 2009,
54.6 percent at September 30, 2008 and
51.5 percent at June 30, 2008. Our ratio of total debt
to capitalization is typically greater during the winter heating
season as we incur short-term debt to fund natural gas purchases
and meet our working capital requirements. We intend to maintain
our debt to capitalization ratio in a target range of 50 to
55 percent through cash flow generated from operations,
continued issuance of new common stock under our Direct Stock
Purchase Plan and Retirement Savings Plan and access to the
equity capital markets.
Contractual
Obligations and Commercial Commitments
Significant commercial commitments are described in Note 8
to the unaudited condensed consolidated financial statements.
There were no significant changes in our contractual obligations
and commercial commitments during the nine months ended
June 30, 2009.
In February 2008, Atmos Pipeline and Storage, LLC announced
plans to construct and operate a salt-cavern gas storage project
in Franklin Parish, Louisiana. The project, located near several
large interstate pipelines, includes the development of three
5 billion cubic feet (Bcf) caverns for a total of
15 Bcf of working gas storage, with six-turn injection and
withdrawal capacity. Testing of the salt core samples was
completed in March 2009 which showed favorable conditions for
development. In June 2009, we received our 7C certification from
the Federal Energy Regulatory Commission (FERC) to construct and
operate the project and expect approval of this request in June
2009. Finally, we have engaged the services of an investment
bank to assist us in determining the optimal ownership
and/or
development alternatives for this project, which is still in
process.
Risk
Management Activities
We conduct risk management activities through our natural gas
distribution, natural gas marketing and pipeline, storage and
other segments. In our natural gas distribution segment, we use
a combination of physical
60
storage, fixed physical contracts and fixed financial contracts
to reduce our exposure to unusually large winter-period gas
price increases.
In our natural gas marketing and pipeline, storage and other
segments, we manage our exposure to the risk of natural gas
price changes and lock in our gross profit margin through a
combination of storage and financial instruments, including
futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. To the extent our inventory cost and actual
sales and actual purchases do not correlate with the changes in
the market indices we use in our hedges, we could experience
ineffectiveness or the hedges may no longer meet the accounting
requirements for hedge accounting, resulting in the financial
instruments being treated as mark to market instruments through
earnings.
The following table shows the components of the change in fair
value of our natural gas distribution segments financial
instruments for the three and nine months ended June 30,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(21,863
|
)
|
|
$
|
9,505
|
|
|
$
|
(63,677
|
)
|
|
$
|
(21,053
|
)
|
Contracts realized/settled
|
|
|
(844
|
)
|
|
|
339
|
|
|
|
(101,840
|
)
|
|
|
(26,971
|
)
|
Fair value of new contracts
|
|
|
(885
|
)
|
|
|
5,675
|
|
|
|
(4,891
|
)
|
|
|
5,395
|
|
Other changes in value
|
|
|
1,564
|
|
|
|
21,847
|
|
|
|
148,380
|
|
|
|
79,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
$
|
(22,028
|
)
|
|
$
|
37,366
|
|
|
$
|
(22,028
|
)
|
|
$
|
37,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of our natural gas distribution segments
financial instruments at June 30, 2009 is presented below
by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at June 30, 2009
|
|
|
|
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
|
|
$
|
(21,712
|
)
|
|
$
|
(316
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(22,028
|
)
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(21,712
|
)
|
|
$
|
(316
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(22,028
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows the components of the change in fair
value of our natural gas marketing segments financial
instruments for the three and nine months ended June 30,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Fair value of contracts at beginning of period
|
|
$
|
(32,646
|
)
|
|
$
|
(22,975
|
)
|
|
$
|
16,542
|
|
|
$
|
26,808
|
|
Contracts realized/settled
|
|
|
42,535
|
|
|
|
30,185
|
|
|
|
29,260
|
|
|
|
(11,071
|
)
|
Fair value of new contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other changes in value
|
|
|
8,555
|
|
|
|
(50,182
|
)
|
|
|
(27,358
|
)
|
|
|
(58,709
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at end of period
|
|
|
18,444
|
|
|
|
(42,972
|
)
|
|
|
18,444
|
|
|
|
(42,972
|
)
|
Netting of cash collateral
|
|
|
20,614
|
|
|
|
62,152
|
|
|
|
20,614
|
|
|
|
62,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash collateral and fair value of contracts at period end
|
|
$
|
39,058
|
|
|
$
|
19,180
|
|
|
$
|
39,058
|
|
|
$
|
19,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
The fair value of our natural gas marketing segments
financial instruments at June 30, 2009 is presented below
by time period and fair value source:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at June 30, 2009
|
|
|
|
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
|
|
$
|
8,544
|
|
|
$
|
9,900
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
18,444
|
|
Prices based on models and other valuation methods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
8,544
|
|
|
$
|
9,900
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
18,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and Postretirement Benefits Obligations
Effective October 1, 2008, the Company adopted the
requirement under SFAS 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R),
that the measurement date used to determine our projected
benefit and postretirement obligations and net periodic pension
and postretirement costs must correspond to a fiscal year end.
In accordance with the transition rules, the impact of changing
the measurement date from June 30, 2008 to
September 30, 2008 decreased retained earnings by
$7.8 million, net of tax, decreased the unrecognized
actuarial loss by $9.0 million and increased our
postretirement liabilities by $3.5 million.
Further, our fiscal 2009 costs were determined using a
September 30, 2008 measurement date. As of
September 30, 2008, interest and corporate bond rates
utilized to determine our discount rates were significantly
higher than the interest and corporate bond rates as of
June 30, 2007, the measurement date for our fiscal
2008 net periodic cost. Accordingly, we increased our
discount rate used to determine our fiscal 2009 pension and
benefit costs to 7.57 percent. We maintained the expected
return on our pension plan assets at 8.25 percent, despite
the recent decline in the financial markets as we believe this
rate reflects the average rate of expected earnings on plan
assets that will fund our projected benefit obligation. Although
the fair value of our plan assets has declined as the financial
markets have declined, the impact of this decline is mitigated
by the fact that assets are smoothed for purposes of
determining net periodic pension cost. Accordingly, asset gains
and losses are recognized over time as a component of net
periodic pension and benefit costs for our Pension Account Plan,
our largest funded plan. Therefore, our fiscal 2009 pension and
postretirement medical costs were materially the same as in
fiscal 2008.
For the nine months ended June 30, 2009 and 2008, our total
net periodic pension and other benefits cost was
$36.2 million and $35.9 million. Those costs relating
to our natural gas distribution operations are recoverable
through our gas distribution rates; however, a portion of these
costs is capitalized into our distribution rate base. The
remaining costs are recorded as a component of operation and
maintenance expense.
In accordance with the Pension Protection Act of 2006 (PPA), we
determined the funded status of our plans as of January 1,
2009. Based upon this valuation, we contributed $21 million
to our pension plans in June 2009. The need for this funding
reflected the decline in the fair value of the plans
assets resulting from the unfavorable market conditions
experienced during the latter half of calendar year 2008. This
contribution increased the level of our plan assets to achieve a
desirable PPA funding threshold. With respect to our
postretirement medical plans, we anticipate contributing a total
of approximately $11 million to these plans during fiscal
2009.
The projected pension liability, future funding requirements and
the amount of pension expense or income recognized for the plan
are subject to change, depending upon the actuarial value of
plan assets and the determination of future benefit obligations
as of each subsequent actuarial calculation date. These amounts
are impacted by actual investment returns, changes in interest
rates and changes in the demographic composition of the
participants in the plan.
62
OPERATING
STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for
our natural gas distribution, regulated transmission and
storage, natural gas marketing and pipeline, storage and other
segments for the three and nine-month periods ended
June 30, 2009 and 2008.
Natural
Gas Distribution Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
METERS IN SERVICE, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,924,160
|
|
|
|
2,922,415
|
|
|
|
2,924,160
|
|
|
|
2,922,415
|
|
Commercial
|
|
|
274,739
|
|
|
|
271,542
|
|
|
|
274,739
|
|
|
|
271,542
|
|
Industrial
|
|
|
2,195
|
|
|
|
2,265
|
|
|
|
2,195
|
|
|
|
2,265
|
|
Public authority and other
|
|
|
9,231
|
|
|
|
9,234
|
|
|
|
9,231
|
|
|
|
9,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,210,325
|
|
|
|
3,205,456
|
|
|
|
3,210,325
|
|
|
|
3,205,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
37.9
|
|
|
|
41.7
|
|
|
|
37.9
|
|
|
|
41.7
|
|
SALES VOLUMES
MMcf(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
19,043
|
|
|
|
18,584
|
|
|
|
147,718
|
|
|
|
151,549
|
|
Commercial
|
|
|
14,398
|
|
|
|
15,199
|
|
|
|
79,416
|
|
|
|
82,325
|
|
Industrial
|
|
|
3,921
|
|
|
|
4,687
|
|
|
|
15,079
|
|
|
|
17,899
|
|
Public authority and other
|
|
|
2,719
|
|
|
|
2,887
|
|
|
|
10,874
|
|
|
|
9,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
40,081
|
|
|
|
41,357
|
|
|
|
253,087
|
|
|
|
261,692
|
|
Transportation volumes
|
|
|
30,637
|
|
|
|
33,211
|
|
|
|
102,091
|
|
|
|
109,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
70,718
|
|
|
|
74,568
|
|
|
|
355,178
|
|
|
|
370,694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING REVENUES
(000s)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
224,629
|
|
|
$
|
352,893
|
|
|
$
|
1,657,185
|
|
|
$
|
1,878,855
|
|
Commercial
|
|
|
106,739
|
|
|
|
213,594
|
|
|
|
744,248
|
|
|
|
903,771
|
|
Industrial
|
|
|
21,028
|
|
|
|
53,843
|
|
|
|
117,442
|
|
|
|
167,154
|
|
Public authority and other
|
|
|
13,712
|
|
|
|
33,135
|
|
|
|
82,097
|
|
|
|
100,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
366,108
|
|
|
|
653,465
|
|
|
|
2,600,972
|
|
|
|
3,050,763
|
|
Transportation revenues
|
|
|
13,756
|
|
|
|
14,163
|
|
|
|
46,411
|
|
|
|
46,954
|
|
Other gas revenues
|
|
|
7,121
|
|
|
|
9,011
|
|
|
|
25,990
|
|
|
|
28,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
386,985
|
|
|
$
|
676,639
|
|
|
$
|
2,673,373
|
|
|
$
|
3,126,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average transportation revenue per Mcf
|
|
$
|
0.45
|
|
|
$
|
0.43
|
|
|
$
|
0.45
|
|
|
$
|
0.43
|
|
Average cost of gas per Mcf sold
|
|
$
|
4.87
|
|
|
$
|
11.53
|
|
|
$
|
7.18
|
|
|
$
|
8.77
|
|
See footnote following these tables.
63
Regulated
Transmission and Storage, Natural Gas Marketing and Pipeline,
Storage and Other Operations Sales and Statistical
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30
|
|
|
June 30
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
CUSTOMERS, end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
|
|
|
706
|
|
|
|
702
|
|
|
|
706
|
|
|
|
702
|
|
Municipal
|
|
|
63
|
|
|
|
56
|
|
|
|
63
|
|
|
|
56
|
|
Other
|
|
|
505
|
|
|
|
503
|
|
|
|
505
|
|
|
|
503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,274
|
|
|
|
1,261
|
|
|
|
1,274
|
|
|
|
1,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVENTORY STORAGE BALANCE Bcf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing
|
|
|
23.3
|
|
|
|
18.8
|
|
|
|
23.3
|
|
|
|
18.8
|
|
Pipeline, storage and other
|
|
|
2.5
|
|
|
|
1.2
|
|
|
|
2.5
|
|
|
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
25.8
|
|
|
|
20.0
|
|
|
|
25.8
|
|
|
|
20.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REGULATED TRANSMISSION AND STORAGE VOLUMES
MMcf(1)
|
|
|
169,641
|
|
|
|
181,112
|
|
|
|
555,169
|
|
|
|
593,452
|
|
NATURAL GAS MARKETING SALES VOLUMES
MMcf(1)
|
|
|
103,146
|
|
|
|
103,403
|
|
|
|
336,870
|
|
|
|
348,789
|
|
OPERATING REVENUES
(000s)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated transmission and storage
|
|
$
|
49,345
|
|
|
$
|
46,286
|
|
|
$
|
163,261
|
|
|
$
|
142,772
|
|
Natural gas marketing
|
|
|
453,504
|
|
|
|
1,189,722
|
|
|
|
1,949,657
|
|
|
|
3,159,092
|
|
Pipeline, storage and other
|
|
|
8,226
|
|
|
|
3,880
|
|
|
|
36,946
|
|
|
|
20,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
511,075
|
|
|
$
|
1,239,888
|
|
|
$
|
2,149,864
|
|
|
$
|
3,322,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note to preceding tables:
|
|
|
(1) |
|
Sales volumes and revenues reflect segment operations, including
intercompany sales and transportation amounts. |
RECENT
ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial
position, results of operations and cash flows are described in
Note 2 to the unaudited condensed consolidated financial
statements.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
Information regarding our quantitative and qualitative
disclosures about market risk are disclosed in Item 7A in
our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. During the
nine months ended June 30, 2009, there were no material
changes in our quantitative and qualitative disclosures about
market risk.
|
|
Item 4.
|
Controls
and Procedures
|
Managements
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the
participation of our management, including our principal
executive officer and principal financial officer, of the
effectiveness of the Companys disclosure controls and
procedures, as such term is defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934, as amended (Exchange
Act). Based on this evaluation, the Companys principal
executive officer and principal financial officer have concluded
that the Companys disclosure controls and procedures were
effective as of June 30, 2009 to provide reasonable
assurance that information
64
required to be disclosed by us, including our consolidated
entities, in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized, and reported
within the time periods specified by the SECs rules and
forms, including a reasonable level of assurance that such
information is accumulated and communicated to our management,
including our principal executive and principal financial
officers, as appropriate to allow timely decisions regarding
required disclosure.
Changes
in Internal Control over Financial Reporting
We did not make any changes in our internal control over
financial reporting (as defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act) during the third quarter of the fiscal
year ended September 30, 2009 that have materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
PART II.
OTHER INFORMATION
|
|
Item 1.
|
Legal
Proceedings
|
During the nine months ended June 30, 2009, except as noted
in Note 8 to the unaudited condensed consolidated financial
statements, there were no material changes in the status of the
litigation and other matters that were disclosed in Note 12
to our Annual Report on
Form 10-K
for the fiscal year ended September 30, 2008. We continue
to believe that the final outcome of such litigation and other
matters or claims will not have a material adverse effect on our
financial condition, results of operations or cash flows.
A list of exhibits required by Item 601 of
Regulation S-K
and filed as part of this report is set forth in the
Exhibits Index, which immediately precedes such exhibits.
65
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Atmos Energy Corporation
(Registrant)
|
|
|
|
By:
|
/s/ Fred
E. Meisenheimer
|
Fred E. Meisenheimer
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: August 5, 2009
66
EXHIBITS INDEX
Item 6
|
|
|
|
|
|
|
Exhibit
|
|
|
|
Page
|
Number
|
|
Description
|
|
Number
|
|
|
10
|
.1
|
|
Form of Award Agreement of Time-Lapse Restricted Stock Units
under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
|
|
|
|
10
|
.2
|
|
Form of Award Agreement of Performance-Based Restricted Stock
Units under the Atmos Energy Corporation 1998 Long-Term
Incentive Plan
|
|
|
|
12
|
|
|
Computation of ratio of earnings to fixed charges
|
|
|
|
15
|
|
|
Letter regarding unaudited interim financial information
|
|
|
|
31
|
|
|
Rule 13a-14(a)/15d-14(a)
Certifications
|
|
|
|
32
|
|
|
Section 1350 Certifications*
|
|
|
|
|
|
* |
|
These certifications, which were made pursuant to 18 U.S.C.
Section 1350 by the Companys Chief Executive Officer
and Chief Financial Officer, furnished as Exhibit 32 to
this Quarterly Report on
Form 10-Q,
will not be deemed to be filed with the Commission or
incorporated by reference into any filing by the Company under
the Securities Act of 1933 or the Securities Exchange Act of
1934, except to the extent that the Company specifically
incorporates such certifications by reference. |
67