UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13
OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the quarterly period ended June 30, 2004 | ||
| or | ||
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o
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TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the transition period from to | ||
Commission File Number 1-10042
Atmos Energy Corporation
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes þ No o
Number of shares outstanding of each of the issuer’s classes of common stock, as of August 2, 2004.
| Class | Shares Outstanding | |
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No Par Value
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62,601,735 |
| PART 1. FINANCIAL INFORMATION | ||||||||
| Item 1. Financial Statements | ||||||||
| Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | ||||||||
| Item 3. Quantitative and Qualitative Disclosures About Market Risk | ||||||||
| Item 4. Controls and Procedures | ||||||||
| PART II. OTHER INFORMATION | ||||||||
| Item 1. Legal Proceedings | ||||||||
| Item 6. Exhibits and Reports on Form 8-K | ||||||||
| EXHIBITS INDEX Item 6(a) | ||||||||
| Revolving Credit Agreement | ||||||||
| Computation of Earnings to Fixed Charges | ||||||||
| Report from Auditors | ||||||||
| Rule 13a-14(a)/15d-14(a) Certifications | ||||||||
| Section 1350 Certifications | ||||||||
PART 1. FINANCIAL INFORMATION
| Item 1. | Financial Statements |
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
| June 30, | September 30, | |||||||||
| 2004 | 2003 | |||||||||
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| (Unaudited) | ||||||||||
| (In thousands) | ||||||||||
| ASSETS | ||||||||||
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Property, plant and equipment
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$ | 2,588,059 | $ | 2,480,139 | ||||||
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Less accumulated depreciation and amortization
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903,313 | 855,745 | ||||||||
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Net property, plant and equipment
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1,684,746 | 1,624,394 | ||||||||
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Current assets
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Cash and cash equivalents
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126,895 | 15,683 | ||||||||
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Cash held on deposit in margin account
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— | 17,903 | ||||||||
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Accounts receivable, net
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243,719 | 216,783 | ||||||||
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Gas stored underground
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90,141 | 168,765 | ||||||||
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Other current assets
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18,710 | 38,863 | ||||||||
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Total current assets
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479,465 | 457,997 | ||||||||
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Goodwill and intangible assets
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275,844 | 273,499 | ||||||||
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Deferred charges and other assets
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240,477 | 271,023 | ||||||||
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| $ | 2,680,532 | $ | 2,626,913 | |||||||
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| CAPITALIZATION AND LIABILITIES | ||||||||||
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Shareholders’ equity
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Common stock, no par value (stated at
$.005 per share); 100,000,000 shares authorized;
issued and outstanding:
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June 30, 2004 —
52,579,303 shares;
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September 30, 2003 —
51,475,785 shares
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$ | 263 | $ | 257 | ||||||
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Additional paid-in capital
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762,464 | 736,180 | ||||||||
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Retained earnings
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167,535 | 122,539 | ||||||||
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Accumulated other comprehensive loss
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(3,416 | ) | (1,459 | ) | ||||||
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Shareholders’ equity
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926,846 | 857,517 | ||||||||
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Long-term debt
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863,266 | 863,918 | ||||||||
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Total capitalization
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1,790,112 | 1,721,435 | ||||||||
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Current liabilities
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Accounts payable and accrued liabilities
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201,123 | 179,852 | ||||||||
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Other current liabilities
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210,759 | 133,957 | ||||||||
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Short-term debt
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— | 118,595 | ||||||||
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Current maturities of long-term debt
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5,918 | 9,345 | ||||||||
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Total current liabilities
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417,800 | 441,749 | ||||||||
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Deferred income taxes
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227,899 | 223,350 | ||||||||
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Regulatory cost of removal obligation
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105,059 | 102,371 | ||||||||
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Deferred credits and other liabilities
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139,662 | 138,008 | ||||||||
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| $ | 2,680,532 | $ | 2,626,913 | |||||||
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See accompanying notes to condensed consolidated financial statements
1
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF
INCOME
Three Months Ended
June 30
2004
2003
(Unaudited)
(In thousands, except
per share data)
$
256,252
$
245,998
364,339
374,832
6,210
3,685
(80,743
)
(136,045
)
546,058
488,470
163,093
161,426
352,708
367,395
3,150
467
(80,385
)
(135,882
)
438,566
393,406
107,492
95,064
50,467
45,141
23,268
23,192
12,297
12,675
86,032
81,008
21,460
14,056
2,187
686
16,011
16,042
7,636
(1,300
)
2,871
(1,099
)
$
4,765
$
(201
)
$
0.09
$
(0.00
)
$
0.09
$
(0.00
)
$
.305
$
.300
52,220
45,997
52,617
45,997
See accompanying notes to condensed consolidated financial statements
2
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF
INCOME
Nine Months Ended
June 30
2004
2003
(Unaudited)
(In thousands, except
per share data)
$
1,425,022
$
1,342,527
1,255,386
1,338,732
20,492
16,242
(273,741
)
(334,457
)
2,427,159
2,363,044
1,003,977
934,649
1,214,395
1,325,655
9,158
1,475
(273,042
)
(333,933
)
1,954,488
1,927,846
472,671
435,198
166,476
151,310
69,879
65,273
45,901
44,057
282,256
260,640
190,415
174,558
7,850
3,321
49,506
47,679
148,759
130,200
56,148
48,303
92,611
81,897
—
(7,773
)
$
92,611
$
74,124
$
1.79
$
1.83
—
(.17
)
$
1.79
$
1.66
$
1.78
$
1.82
—
(.17
)
$
1.78
$
1.65
$
.915
$
.900
51,788
44,679
52,166
44,879
See accompanying notes to condensed consolidated financial statements
3
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH
FLOWS
Nine Months Ended
June 30
2004
2003
(Unaudited)
(In thousands)
$
92,611
$
74,124
—
7,773
(6,700
)
—
69,879
65,273
1,270
1,676
5,750
9,148
(1,405
)
(5,403
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4,469
(4,200
)
193,388
(31,099
)
359,262
117,292
(129,508
)
(113,637
)
27,919
—
(505
)
315
(1,957
)
(74,650
)
(104,051
)
(187,972
)
(118,595
)
(145,091
)
(47,615
)
(39,893
)
(9,079
)
(72,333
)
5,000
253,267
26,290
19,336
—
(70,938
)
—
147,000
—
(147,000
)
—
96,826
(143,999
)
41,174
111,212
(29,506
)
15,683
46,827
$
126,895
$
17,321
See accompanying notes to condensed consolidated financial statements
4
ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
1. Nature of
Business
Atmos Energy Corporation and its subsidiaries are
engaged primarily in the natural gas utility business as well as
certain nonutility businesses. Through our natural gas utility
business, we distribute natural gas through sales and
transportation arrangements to approximately 1.7 million
residential, commercial, public-authority and industrial
customers through our six regulated natural gas utility
divisions, which cover the following service areas:
In addition, we transport natural gas for others
through our distribution system. Our utility business is subject
to federal and state regulation and/or regulation by local
authorities in each of the states in which the utility divisions
operate. Our shared-services division is located in Dallas,
Texas, and our customer support centers are located in Amarillo,
Texas, and Metairie, Louisiana.
As further described in Note 3, on
June 17, 2004, we entered into a definitive agreement with
TXU Gas Company (TXU Gas) to acquire the natural gas
distribution and pipeline operations of TXU Gas. The acquisition
would increase the number of customers we serve in our natural
gas utility business to over 3.1 million and make us one of
the largest publicly-traded companies in the United States whose
primary business is the transmission and distribution of natural
gas and the provision of related services. It would also make us
one of the largest intrastate pipeline operators in Texas.
Our nonutility businesses are organized under
Atmos Energy Holdings, Inc. (AEH), and have operations in
18 states. Through September 30, 2003, Atmos Energy
Marketing, LLC, together with its wholly-owned subsidiaries,
Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas
Company, Inc., comprised our natural gas marketing segment.
Effective October 1, 2003, our natural gas marketing
segment was reorganized. The operations of Atmos Energy
Marketing, LLC and Trans Louisiana Industrial Gas Company, Inc.
were merged into Woodward Marketing, L.L.C., which was renamed
Atmos Energy Marketing, LLC (AEM).
AEM provides a variety of natural gas management
services to municipalities, natural gas utility systems and
industrial natural gas consumers, primarily in the southeastern
and midwestern states and to our Colorado-Kansas, Kentucky,
Louisiana and Mid-States divisions. These services consist
primarily of furnishing natural gas supplies at fixed and
market-based prices, contract negotiation and administration,
load forecasting, gas storage acquisition and management
services, transportation services, peaking sales and balancing
services, capacity utilization strategies and gas price hedging
through the use of derivative instruments.
Our other nonutility businesses consist primarily
of the operations of Atmos Pipeline and Storage, L.L.C., Atmos
Power Systems, Inc. and Atmos Energy Services, LLC (AES), all of
which are wholly-owned by
5
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
AEH. Through Atmos Pipeline and Storage, L.L.C.,
we own or have an interest in underground storage fields in
Kentucky and Louisiana. Through Atmos Pipeline and Storage,
L.L.C. we provide storage services to our customers for a fee,
as well as capture pricing arbitrage through the use of
derivatives. Through Atmos Power Systems, Inc., we construct
electric peaking power-generating plants and associated
facilities and may enter into agreements to either lease or sell
these plants. Through AES, we provide natural gas management
services. Prior to the third quarter of fiscal 2004, this entity
conducted limited operations. However, beginning April 1,
2004, AES began providing natural gas supply management services
to our utility operations in a limited number of states. We
expect to expand these services to substantially all of our
utility service areas before the end of fiscal 2004.
Prior to January 20, 2004, United Cities
Propane Gas, Inc., a wholly owned subsidiary of AEH, owned an
approximate 19 percent membership interest in
U.S. Propane L.P. (USP), a joint venture formed in February
2000 with three other utility companies. Through our ownership
in USP, we owned an approximate 5 percent indirect interest
in Heritage Propane Partners, L.P. On January 20, 2004, we
and our partners in USP completed the sale of our general and
limited partnership interests in USP for $130.0 million. We
received cash proceeds of approximately $24.7 million and
recorded a $4.9 million pretax book gain in the second
quarter of fiscal 2004. In June 2004, we received cash proceeds
of $1.9 million attributable to the final sale of all
remaining Heritage Propane Partners, L.P. limited partnership
units formerly owned by USP and recognized a $1.0 million
pretax book gain. With these transactions, we no longer have an
interest in the propane industry.
In the opinion of management, all material
adjustments (consisting of normal recurring accruals) necessary
for a fair presentation have been made to the unaudited
consolidated interim-period financial statements. These
consolidated interim-period financial statements and notes are
condensed as permitted by the instructions to Form 10-Q and
should be read in conjunction with the audited consolidated
financial statements of Atmos Energy Corporation
(“Atmos” or “the Company”) in its Annual
Report on Form 10-K for the fiscal year ended
September 30, 2003. Because of seasonal and other factors,
the results of operations for the three- and nine-month periods
ended June 30, 2004, are not indicative of expected results
of operations for the fiscal year ending September 30, 2004.
Our accounting policies are described in
Note 2 to our Annual Report on Form 10-K for the year
ended September 30, 2003. As described in our Annual Report
on Form 10-K, our utility depreciation rates approved by
the various regulatory commissions included a component that
allowed us to recover the cost of removing our assets.
Historically, we recorded the associated obligation as a
component of accumulated depreciation. This classification was
consistent with others in the industry. Beginning in the second
quarter of fiscal 2004, we are classifying our regulatory cost
of removal obligation as a regulatory liability on the balance
sheet. Additionally, for purposes of our September 30, 2003
information presented in this report, we reclassified from
accumulated depreciation to regulatory liabilities a total of
$108.4 million in regulatory cost of removal accruals at
September 30, 2003, of which $102.4 million was a
long-term regulatory liability. These reclassifications do not
impact our financial position, results of operations, cash flows
or ability to satisfy our financial covenants contained in our
various credit agreements as of June 30, 2004 and
September 30, 2003.
Effective April 1, 2004, we elected to treat
our fixed-price forward contracts as normal purchases and sales.
As a result, we ceased marking the fixed-price forward contracts
to market. We have designated the offsetting derivative
contracts as cash flow hedges of anticipated transactions. As a
result of this change, unrealized gains and losses on these open
derivative contracts are now recorded as a component of
accumulated other comprehensive income and are recognized in
earnings when the hedged volumes are sold.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
This designation is expected to partially reduce
the amount of volatility in our condensed consolidated income
statement and better reflect the economics of this type of
transaction.
We have two stock-based compensation plans that
provide for the granting of incentive stock options,
nonqualified stock options, stock appreciation rights, bonus
stock, restricted stock and performance-based stock to officers
and key employees: the 1998 Long-Term Incentive Plan and the
Long-Term Stock Plan for the Mid-States Division. Nonemployee
directors are also eligible to receive such stock-based
compensation under the 1998 Long-Term Incentive Plan. The
objectives of these plans include attracting and retaining the
best personnel, providing for additional performance incentives
and promoting our success by providing employees with the
opportunity to acquire common stock.
As permitted by Statement of Financial Accounting
Standard (SFAS) 123,
Accounting for Stock-Based
Compensation,
we account for these plans under the
intrinsic-value method described in Accounting Principles Board
(APB) Opinion 25,
Accounting for Stock Issued to
Employees.
Under this method, no compensation cost for stock
options is recognized for stock-option awards granted at or
above fair-market value.
Awards of restricted stock are valued at the
market price of the Company’s common stock on the date of
grant. The unearned compensation is amortized to operation and
maintenance expense over the vesting period of the restricted
stock.
Had compensation expense for our stock options
issued under the Long-Term Incentive Plan been recognized based
on the fair value on the grant date under the methodology
prescribed by SFAS 123, our net income (loss) and earnings
(loss) per share for the three months and nine months ended
June 30, 2004 and 2003 would have been impacted as shown in
the following table:
No option grants have occurred under the
Long-Term Stock Plan for the Mid-States Division since that
entity was acquired in 1997. Due to the limited activities of
that plan, the pro forma effect of applying SFAS 123 would
have had less than a $0.01 per diluted share effect on
earnings per share for the three and
7
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
nine months ended June 30, 2004 and 2003, or
$160 and $416 for the three months ended June 30, 2004 and
2003 and $922 and $1,922 for the nine months ended June 30,
2004 and 2003.
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. Significant regulatory assets and
liabilities as of June 30, 2004 and September 30, 2003
included the following:
Currently authorized rates do not include a
return on our merger and integration costs; however, we recover
the amortization of these costs. Merger and integration costs,
net, are amortized on a straight-line basis over estimated
useful lives ranging from 7 to 20 years. These costs will
have been substantially amortized by December 2004. Certain
environmental costs have been deferred to future rate filings in
accordance with rulings received from various regulatory
commissions.
8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents the components of
comprehensive income, net of related tax, for the three- and
nine-month periods ended June 30, 2004 and 2003:
Accumulated other comprehensive income consists
of unrealized holding gains and losses associated with certain
available-for-sale investments and unrealized gains and losses
associated with commodity and interest rate hedging
transactions. In connection with the pending acquisition of the
TXU Gas operations, the Company entered into Treasury interest
rate locks associated with $675.0 million of long-term debt
to be issued in connection with the acquisition (see
Note 5).
In January 2003, the Financial Accounting
Standards Board (FASB) issued FASB Interpretation
(FIN) 46,
Consolidation of Variable Interest Entities,
An Interpretation of Accounting Research Bulletin
No. 51.
The primary objectives of FIN 46 are to
provide guidance on how to identify entities for which control
is achieved through means other than through voting rights
(variable interest entities (VIE)) and how to determine when to
consolidate and which business enterprises should consolidate
the VIE. The adoption of this interpretation did not have a
material impact on our financial position, results of operations
or net cash flows because we are not currently a beneficiary of
a VIE.
During 2003, the Emerging Issues Task Force (the
Task Force) added to its agenda Emerging Issues Task Force
(EITF) Issue 03-01,
The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain
Investments,
to address the meaning of
“other-than-temporary” impairment and its application
to certain investments carried at cost. In November 2003, the
Task Force developed new disclosure requirements concerning
unrealized losses on available-for-sale debt and equity
securities accounted for under SFAS 115,
Accounting for
Certain Investments in Debt and Equity Securities,
which
will be applicable to us beginning with our fiscal 2004 Annual
Report on Form 10-K.
In December 2003, the FASB issued SFAS 132
(revised),
Employers’ Disclosures about Pensions and
Other Postretirement Benefits.
These revisions require
additional disclosures in annual reports on Form 10-K
concerning the assets, obligations, cash flows and net
periodic-benefit cost of defined-benefit pension plans and other
defined-benefit postretirement plans. Additionally, the
statement now requires interim-period disclosures regarding net
periodic pension cost and employer contributions. The annual
disclosures will become fully
9
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
effective for fiscal years ending after
June 15, 2004, and the interim-period disclosures were
effective for interim periods beginning after December 15,
2003. We have adopted the interim-period disclosures, which are
contained in Note 8, and will adopt the annual disclosures
beginning with our fiscal 2004 Annual Report on Form 10-K.
In January 2004, the FASB issued FASB Staff
Position FAS 106-1,
Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003,
which permits a
plan sponsor to defer recognizing the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003
(the Act) in accounting for its plan under SFAS 106 and in
providing disclosures related to the plan required by
SFAS 132 (revised). We elected to recognize the provisions
of the Act, beginning with the second quarter of fiscal 2004,
which reduced our accumulated postretirement benefit obligation
and our net postretirement benefit obligation costs by
$4.1 million based upon calculations prepared by our
independent actuaries. The total income statement impact for
fiscal 2004 will approximate $2.3 million, as a portion of
this benefit will be capitalized.
3. Acquisitions
On June 17, 2004, we entered into a
definitive agreement with TXU Gas Company (TXU Gas) to acquire
the natural gas distribution and pipeline operations of TXU Gas.
The TXU Gas operations we are acquiring are
regulated businesses engaged in the purchase, transmission,
storage, distribution and sale of natural gas in the
north-central, eastern and western parts of Texas. TXU Gas
provides gas distribution services to over 1.4 million
residential and business customers in Texas, including the
Dallas/ Fort Worth metropolitan area. TXU Gas owns and
operates a system consisting of 6,162 miles of gas
transmission and gathering lines and five underground storage
reservoirs, all within Texas. The acquisition would increase the
number of customers we serve in our distribution business to
over 3.1 million.
The purchase price, excluding transaction costs,
for the acquisition is $1.925 billion, which is payable in
cash. The price is subject to adjustment if at the time of
closing the working capital of TXU Gas is less or more than
approximately $121 million. The price is also subject to
increase by the amount of any capital expenditures made by TXU
Gas prior to closing that exceed its budgeted amounts. We are
not assuming any indebtedness in the transaction. TXU Gas has
agreed to repay or redeem all of its existing indebtedness and
its preferred stock and to retain or pay certain other
liabilities under the terms of the acquisition agreement.
We have received a commitment from a third party
financial institution, subject to customary conditions, to
provide a senior unsecured credit facility in the amount of
$1.925 billion to finance, or backstop the issuance of
commercial paper to finance, this acquisition. The bridge
financing facility will mature 364 days after the closing
date of the acquisition. The commitment is subject to the
absence of a material adverse effect on our business and assets,
after giving effect to the acquisition, the absence of any new
adverse information affecting us, TXU Gas or the acquisition
that would materially impair the syndication of the bridge
financing facility and other specified conditions. The amount of
the bridge financing facility will be reduced to the extent we
obtain acquisition financing prior to the closing of the
acquisition. As further described in Note 12, in July 2004,
we sold 9,939,393 common shares, which generated net proceeds of
$236.2 million before legal, accounting and other offering
costs, that will be used to reduce the amount we intend to
borrow under this facility. We intend to seek long-term debt and
additional common equity financings to refinance the bridge
financing facility.
We expect the acquisition to close by the end of
the calendar year 2004; however, this acquisition is subject to
the satisfaction of several conditions, including regulatory
approvals in three states and clearance by antitrust
authorities. The 30-day waiting period under the
Hart-Scott-Rodino Act expired August 2, 2004 with
10
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
no inquiries from the Justice Department or
Federal Trade Commission. In addition, the Virginia State
Corporation Commission issued an order on August 6, 2004
approving the short-term debt financing for the acquisition,
while regulatory approvals from the state regulatory commissions
in Iowa and Missouri are pending. If we have not obtained our
three state regulatory approvals by December 31, 2004 and
the other conditions to closing have been satisfied, TXU Gas may
terminate the agreement and require us to pay $15 million
in full satisfaction of our obligations under the agreement. In
addition, we or TXU Gas may terminate the agreement if the
applicable closing conditions are not satisfied or waived by
December 31, 2004. The closing date may be extended for up
to 90 days to the extent required for TXU Gas to repair any
material casualty loss incurred before closing.
Effective March 1, 2004, we completed the
acquisition of the natural gas distribution assets of ComFurT
Gas Inc., a privately held natural gas utility and propane
distributor based in Buena Vista, Colorado, for approximately
$2.0 million in cash. This company served approximately
1,800 natural gas utility customers. The acquisition enabled us
to expand our contiguous service area in our Colorado-Kansas
division. Unaudited pro forma results of the Company and ComFurT
have not been presented as the acquisition was not material to
our financial position or results of operations.
Goodwill and intangible assets are comprised of
the following as of June 30, 2004 and September 30,
2003.
The following presents our goodwill balance
allocated by segment and changes in our balance for the nine
months ended June 30, 2004:
During the second quarter of fiscal 2004, we
completed our annual goodwill impairment assessment. Based upon
the assessment performed, our goodwill was not considered to be
impaired.
We conduct risk management activities through
both our utility and natural gas marketing segments. We record
our derivatives as a component of risk management assets and
liabilities, which are classified as current or noncurrent based
upon the anticipated settlement date of the underlying
derivative. Our determination of the fair value of these
derivative financial instruments reflects the estimated amounts
that we would receive or
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
pay to terminate or close the contracts at the
reporting date, taking into account the current unrealized gains
and losses on open contracts. In our determination of fair
value, we consider various factors, including closing exchange
and over-the-counter quotations, time value and volatility
factors underlying the contracts.
The following table shows the fair values of our
risk management assets and liabilities by segment at
June 30, 2004 and September 30, 2003:
We use a combination of storage, fixed-price
physical contracts and fixed-price financial contracts to
protect us and our customers against unusually large
winter-period gas price increases. For the 2003-2004 heating
season, we hedged between 50 and 55 percent of our winter
flowing gas requirements at a weighted average cost of
approximately $5.36 per MCF. These derivative financial
instruments are marked to market pursuant to SFAS 133,
Accounting for Derivative Financial Instruments and Hedging
Activities.
Because these costs will ultimately be recovered
through our rates, current-period changes in the assets and
liabilities from risk management activities are recorded as a
component of deferred gas costs in accordance with SFAS 71
and recognized in purchased gas cost in the income statement
when the related costs are recovered through our rates.
Accordingly, there is no earnings impact as a result of the use
of these financial instruments in our utility segment.
In June 2001, we purchased a three-year
weather-insurance policy with an option to cancel the third year
of coverage. The insurance covered our Texas and Louisiana
operations to protect against weather that was at least
7 percent warmer than normal for the entire heating season
of October through March, beginning with the 2001-2002 heating
season. The prepaid cost of the three-year policy was
$13.2 million and was amortized over the appropriate
heating seasons based on heating degree days. In the third
quarter of fiscal 2003, we cancelled this policy, primarily as a
result of rate relief in Louisiana and prospects for weather
normalization adjustments in Texas. During the three months and
nine months ended June 30, 2003, we recognized amortization
expense of $0.6 million and $5.0 million. However, we
did not collect under this policy because weather was not at
least 7 percent warmer than normal.
12
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Our natural gas marketing hedging activities are
conducted through AEM. AEM is exposed to risks associated with
changes in the market price of natural gas, and we manage our
exposure to the risk of natural gas price changes through a
combination of storage and financial derivatives, including
futures, over-the-counter and exchange-traded options and swap
contracts with counterparties. 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. The use of these contracts
is subject to our risk management policies, which are monitored
for compliance on a daily basis.
We participate in transactions in which we
combine the natural gas commodity and transportation costs to
minimize our costs incurred to serve our customers.
Additionally, we engage in natural gas storage transactions in
which we seek to find and profit from pricing differences that
occur over time. We purchase or sell physical natural gas and
then sell or purchase financial contracts at a price sufficient
to cover our carrying costs and provide a gross profit margin.
Through the use of transportation and storage services and
derivatives, we are able to capture gross profit margin through
the arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
Under SFAS 133, natural gas inventory is the
hedged item in a fair-value hedge and is marked to market on a
monthly basis using the inside FERC (iFERC) price at the end of
each month. Changes in fair value are recognized as unrealized
gains and losses in the period of change. Costs to store the gas
are recognized in the period the costs are incurred. We
recognize revenue and the carrying value of the inventory as an
associated purchased gas cost in our condensed consolidated
statement of income when we sell the gas and deliver it out of
the storage facility.
Derivatives associated with our storage gas
contracts 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 difference in the
indices used to mark to market our physical inventory (iFERC)
and the related fair-value hedge (NYMEX) can result in
volatility in our reported net income. Over time, gains and
losses on the sale of storage gas inventory will be offset by
gains and losses on the fair-value hedges, resulting in the
realization of the economic gross profit margin we anticipated
at the time we structured the original transaction.
Similar to our inventory position, we attempt to
mitigate substantially all of the commodity price risk
associated with our fixed-price contracts with minimum volume
requirements through the use of various offsetting derivatives.
Prior to April 1, 2004, these derivatives were not
designated as hedges under SFAS 133 because they naturally
locked in the economic gross profit margin at the time we enter
into the contract. The fixed-price forward and offsetting
derivative contracts were marked to market each month with
changes in fair value recognized as unrealized gains and losses
in our condensed consolidated statement of income. The
unrealized gains and losses are realized in the period in which
we fulfill the requirements of the fixed-price contract and the
derivatives are settled. To the extent that the unrealized gains
and losses of the fixed-price forward contracts and the
offsetting derivatives do not offset exactly, our earnings will
experience some volatility. At delivery, the gains and losses on
the fixed-price contracts were offset by gains and losses on the
derivatives, resulting in the realization of the economic gross
profit margin we anticipated at the time we structured the
original transaction.
Effective April 1, 2004, we elected to treat
our fixed-price forward contracts as normal purchases and sales.
As a result, we ceased marking the fixed-price forward contracts
to market. We have designated the offsetting derivative
contracts as cash flow hedges of anticipated transactions. As a
result of this change, unrealized gains and losses on these open
derivative contracts are now recorded as a component of
accumulated other comprehensive income and are recognized in
earnings when the hedged volumes are sold.
13
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
This designation is expected to partially reduce
the amount of volatility in our condensed consolidated income
statement and more accurately reflect the economics of this type
of transaction.
For the three and nine months ended
June 30, 2004, the increase in the deferred hedging gain in
accumulated other comprehensive income was attributable to the
initiation of cash flow hedge accounting treatment described
above and increases in future commodity prices relative to the
commodity prices stipulated in the derivative contracts,
partially offset by the reclassification of $2.6 million in
net deferred hedge gains to net income as derivatives matured
according to their terms. The net deferred hedge losses
associated with open cash flow hedges remain subject to market
price fluctuations until the positions are either settled under
the terms of the hedge contracts or terminated prior to
settlement. The deferred hedging gain as of June 30, 2004
is expected to be substantially recognized within the next
six months.
Under our risk management policies, we seek to
match our financial derivative positions to our physical storage
positions as well as our expected current and future sales and
purchase obligations to maintain no open positions at the end of
each trading day. The determination of our net open position as
of any day, however, requires us to make assumptions as to
future circumstances, including the use of gas by our customers
in relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. We 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, 2004, AEH
had a net open position (including existing storage) of
0.4 Bcf.
On January 1, 2003, we recorded a cumulative
effect of a change in accounting principle to reflect a change
in the way we account for our storage and transportation
contracts. Previously we accounted for those contracts under
EITF 98-10,
Accounting for Energy Trading and Risk
Management Activities
, which required us to record estimated
future gains on our storage and transportation contracts at the
time we entered into the contracts and to mark those contracts
to market value each month. Effective January 1, 2003, we
no longer marked those contracts to market. As a result, we
expensed $7.8 million, net of applicable income tax
benefit, as a cumulative effect of a change in accounting
principle.
In June 2004, we entered into two Treasury lock
agreements to fix the Treasury yield component of the interest
cost of financing associated with the anticipated issuance of
$675 million of long-term debt. This long-term debt will be
used to refinance a portion of the 364-day bridge financing
facility that will be used to finance the TXU Gas acquisition on
an interim basis, as described in Note 3. The Treasury
locks are scheduled to terminate on December 31, 2004;
however, we have the ability to terminate the locks at our
discretion within 60 days of December 31, 2004.
We have designated these Treasury locks as cash
flow hedges of an anticipated transaction. Accordingly, to the
extent effective, unrealized gains and losses associated with
the Treasury locks will be recorded as a component of
accumulated other comprehensive income. Unrealized gains will be
recorded when interest rates increase and unrealized losses will
be recorded when interest rates decline. Upon termination of the
Treasury lock agreements, the unrealized gain or loss will be
recognized over the life of the related financing arrangement.
Any gains or losses arising from ineffectiveness will be
recognized into earnings as incurred. At June 30, 2004, we
recorded deferred hedging losses of $4.4 million, net of
tax, as a component of accumulated other comprehensive income
related to these Treasury locks due to a decline in the 5 and
10 year Treasury rates between the inception of the
Treasury locks and June 30, 2004.
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Long-term debt at June 30, 2004 and
September 30, 2003 consisted of the following:
Most of the First Mortgage Bonds contain
provisions that allow us to prepay the outstanding balance in
whole at any time, subject to a prepayment premium. The First
Mortgage Bonds provide for certain cash flow requirements and
restrictions on additional indebtedness, sale of assets and
payment of dividends. Under the most restrictive of such
covenants, cumulative cash dividends paid after
December 31, 1988, may not exceed the sum of accumulated
net income for periods after December 31, 1988, plus
$15.0 million. At June 30, 2004, approximately
$129.1 million of retained earnings were unrestricted with
respect to the payment of dividends. We were in compliance with
all of our debt covenants as of June 30, 2004.
At June 30, 2004, there were no short-term
amounts outstanding under our commercial paper program or bank
credit facilities. At September 30, 2003, short-term debt
consisted of $118.6 million of commercial paper. No amounts
were outstanding under our bank credit facilities at
September 30, 2003.
Credit
Facilities
We maintain both committed and uncommitted credit
facilities. Borrowings under our uncommitted credit facilities
are made on a when-and-as-needed basis at the discretion of the
bank. Our credit capacity and the amount of unused borrowing
capacity are affected by the seasonal nature of the natural gas
business and
15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
our short-term borrowing requirements, which are
typically highest during colder winter months. Our working
capital needs can vary significantly due to changes in the price
of natural gas charged by suppliers and the increased gas
supplies required to meet customers’ needs during periods
of cold weather.
We have two short-term committed credit
facilities totaling $368.0 million, one of which is an
unsecured facility for $350.0 million that bears interest
at the Eurodollar rate plus 0.625 percent and serves as a
backup liquidity facility for our commercial paper program. In
July 2004, we renewed this facility on substantially the same
terms as those of the existing facility, and it will expire in
January 2005. We expect that this facility will be resized and
renewed following the closing of the acquisition of the TXU Gas
operations. We have a second unsecured facility in place for
$18.0 million that bears interest at the Fed Funds rate
plus 0.5 percent and is used for working-capital purposes.
At June 30, 2004, there were no amounts outstanding under
these credit facilities. These credit facilities are negotiated
at least annually. On April 1, 2004, the $18.0 million
working-capital credit facility was renewed for an additional
12 months on terms substantially similar to those of the
prior facility.
The availability of funds under our credit
facilities is subject to conditions specified in the respective
credit agreements, all of which we currently meet. These
conditions include our compliance with financial covenants and
the continued accuracy of representations and warranties
contained in these agreements. We are required by the financial
covenants in our $350.0 million credit facility to maintain
a ratio of total debt to total capitalization of no greater than
70 percent. At June 30, 2004, our
total-debt-to-total-capitalization ratio, as defined, was
50 percent. In addition, both the interest margin over the
Eurodollar rate and the fee that we pay on unused amounts under
our $350.0 million credit facility are subject to
adjustment depending upon our credit ratings. We and our lead
bank plan to amend this facility’s terms prior to closing
the TXU Gas acquisition to accommodate the expected increase in
our debt to capital ratio that will result from the acquisition.
AEM has a $250.0 million uncommitted-demand
working capital credit facility that bears interest at the
Eurodollar rate plus 2.5 percent and expires on
March 31, 2005. Effective October 1, 2003, with the
reorganization of our natural gas marketing segment, AEM became
the borrower under the credit facility, and AEH became the sole
guarantor of the facility. At June 30, 2004, no amounts
were outstanding under this credit facility. AEM letters of
credit totaling $74.2 million reduced the amount available
in accordance with the terms of the facility. 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 $57.8 million at June 30,
2004.
We also have an unsecured short-term uncommitted
credit line for $25.0 million that is used for
working-capital and letter-of-credit purposes. There were no
borrowings under this uncommitted credit facility at
June 30, 2004, but Atmos Energy Corporation
(AEC) letters of credit reduced the amount available by
$3.5 million. This uncommitted line is renewed or
renegotiated at least annually with varying terms, and we pay no
fee for the availability of the line. Borrowings under this line
are made on a when- and as-available basis at the discretion of
the bank.
In addition, AEM has a $100.0 million
intercompany credit facility with AEC through AEH for its
nonutility business which bears interest at the Eurodollar rate
plus 2.75 percent. Any outstanding amounts under this
facility are subordinated to AEM’s $250.0 million
uncommitted-demand credit facility described above. This
facility is used to supplement AEM’s $250.0 million
credit facility. This credit facility was renewed effective
July 1, 2004 on substantially the same terms as those of
the existing facility and has been approved by our state
regulators through December 31, 2004. However, there is no
assurance that our
16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
regulators will approve our use of this credit
facility after that time. At June 30, 2004,
$20.0 million was outstanding under this facility.
Basic and diluted earnings per share at
June 30 are calculated as follows:
There were approximately 84,000 options and
approximately 122,000 shares of restricted stock as of
June 30, 2003 that were excluded from the calculation of
diluted earnings per share for the three months ended
June 30, 2003 as their inclusion in the computation would
be anti-dilutive.
There were no options excluded from the
computation of diluted earnings per share for the three months
ended June 30, 2004 as the exercise price for all options
was less than the average market price of the common stock
during that period. There were 577,500 out-of-the-money options
excluded from the computation of diluted earnings per share for
the three months ended June 30, 2003 as their exercise
price was greater than the average market price of the common
stock during that period.
There were 3,000 and 577,500 out-of-the-money
options excluded from the computation of diluted earnings per
share for the nine months ended June 30, 2004 and 2003 as
their exercise price was greater than the average market price
of the common stock during that period.
17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The components of our net periodic pension cost
for our pension and other postretirement benefit plans for the
three months ended June 30, 2004 and 2003 are presented
below. The 2004 amounts reflect the impact of adopting the
provisions of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) beginning in the second
quarter of fiscal 2004.
The components of our net periodic pension cost
for our pension and other post-retirement benefit plans for the
nine months ended June 30, 2004 and 2003 are as follows:
A portion of these costs is capitalized into our
utility rate base, as these costs are recoverable through our
gas utility rates. Costs that are not capitalized are recorded
as a component of operating expense.
The assumptions used to develop our net periodic
pension cost for the three and nine months ended June 30,
2004 and 2003 are as follows:
In our Annual Report on Form 10-K for the
year ended September 30, 2003, we disclosed that
anticipated additional voluntary contributions ranging from $0
to $15 million during fiscal 2004 may be necessary to keep
the Atmos Energy Corporation Pension Account Plan (the Pension
Account Plan) 100 percent funded on an accumulated benefit
obligation (ABO) basis. We did not contribute to our pension
18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
plan during the nine months ended June 30,
2004 and we do not anticipate voluntarily contributing to the
Pension Account Plan during the remainder of fiscal 2004.
On September 23, 1999, a suit was filed in
the District Court of Stevens County, Kansas, by Quinque
Operating Company, Tom Boles and Robert Ditto against more than
200 companies in the natural gas industry, including us and
our Colorado-Kansas Division. The plaintiffs, who purport to
represent a class consisting of gas producers, royalty owners,
overriding royalty owners, working interest owners and state
taxing authorities, allege that the defendants have underpaid
royalties on gas taken from wells situated on nonfederal and
non-Indian lands throughout the United States and offshore
waters, predicated upon allegations that the defendants’
gas measurements are simply inaccurate and that the defendants
failed to comply with applicable regulations and industry
standards over the last 25 years. Although the plaintiffs
do not specifically allege an amount of damages, they contend
that this suit is brought to recover billions of dollars in
revenues that the defendants have allegedly unlawfully diverted
from the plaintiffs to themselves. On April 10, 2000, this
case was consolidated for pretrial proceedings with other
similar pending litigation in federal court in Wyoming in which
we are also a defendant, along with more than 200 other
defendants, in the case of In Re Natural Gas Royalties Qui Tam
Litigation. In January 2001, the federal court elected to remand
this case to the Kansas state court. A reconsideration of remand
was filed, but it was denied. The state court now has
jurisdiction over this proceeding and has issued a preliminary
case management order. On April 10, 2003, the court denied
the plaintiffs’ motion to certify this proceeding as a
class action, which ruling was appealed by the plaintiffs. The
court did allow the plaintiffs to file an amended complaint,
which is somewhat narrower in scope than the original complaint.
There have since been no material developments in this case. We
continue to believe that the plaintiffs’ claims are lacking
in merit, and we intend to continue to vigorously defend this
action. While the results of this litigation cannot be predicted
with certainty, we believe the final outcome of such litigation
will not have a material adverse effect on our financial
condition, results of operations or net cash flows.
On February 13, 2002, a suit was filed in
the 287th District Court of Parmer County, Texas, by Anderson
Brothers, a Partnership, against Atmos Energy Corporation,
et al.
The plaintiffs’ claims arise out of an
alleged breach of contract by us and by a number of our
divisions and subsidiaries concerning the sale of natural gas
used in irrigation activities since 1998 and an alleged
violation of the Texas Agricultural Gas Users Act of 1985. We
have reached a tentative settlement with the plaintiffs’
attorneys in this case. A fairness hearing will be held on the
proposed settlement agreement on August 24, 2004. The
settlement agreement must be approved by the court and then by
the plaintiffs as a class, which is expected by the end of
October 2004. We believe the final outcome of this litigation
will not have a material adverse effect on our financial
condition, results of operations or net cash flows.
We are a plaintiff in a case styled Energas
Company, a Division of Atmos Energy Corporation v. ONEOK
Energy Marketing and Trading Company, L.P., ONEOK Westex
Transmission, Inc., and ONEOK Energy Marketing and Trading
Company II, filed in December 2001, pending in the District
Court of Lubbock County, Texas, 72nd Judicial District. In
this case, we are seeking to collect our receivable related to
approximately 5.0 Bcf of natural gas that we believe was
not delivered. We have settled a portion of our claims with the
parties and will continue to pursue recovery of the remaining
claims, which we believe are fully recoverable. We are
proceeding with discovery in this case, which has been set for
trial in 2005.
19
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
United Cities Propane Gas, Inc., one of our
wholly-owned subsidiaries, is a party to an action filed in June
2000 that is pending in the Circuit Court of Sevier County,
Tennessee. The plaintiffs’ claims arise out of injuries
alleged to have been caused by a low-level propane explosion.
The plaintiffs seek to recover damages of $13.0 million.
Discovery activities continue in this case. We have denied any
liability, and we intend to vigorously defend against the
plaintiffs’ claims. This case has been set for trial on
November 1, 2004. While the results of this litigation
cannot be predicted with certainty, we believe the final outcome
of such litigation will not have a material adverse effect on
our financial condition, results of operations or net cash flows.
We are a party to other litigation and claims
that arise in the ordinary course of our business. While the
results of such litigation and claims cannot be predicted with
certainty, we believe the final outcome of such litigation and
claims will not have a material adverse effect on our financial
condition, results of operations or net cash flows.
We are the owner or previous owner of
manufactured gas plant sites in Johnson City and Bristol,
Tennessee, and Hannibal, Missouri, which were used to supply gas
prior to the availability of natural gas. The gas manufacturing
process resulted in certain byproducts and residual materials,
including coal tar. The manufacturing process used by our
predecessors was an acceptable and satisfactory process at the
time such operations were being conducted. Under current
environmental protection laws and regulations, we may be
responsible for response actions with respect to such materials
if response actions are necessary.
United Cities Gas Company and the Tennessee
Department of Environment and Conservation (TDEC) entered
into a consent order effective January 23, 1997, to
facilitate the investigation, removal and remediation of the
Johnson City site. Prior to our merger with United Cities Gas
Company in July 1997, United Cities Gas Company began the
implementation of the consent order in the first quarter of
fiscal 1997, which we continued through June 30, 2004. The
investigative phase of the work at the site has been completed,
and an interim removal action was completed in June 2001. We
installed four groundwater monitoring wells at the site in 2002
and have submitted the analytical results to the TDEC. We have
completed a risk assessment report that has been approved by the
TDEC. Finally, we have completed a feasibility study for this
site, which was submitted to the TDEC in October 2003. The
feasibility study recommends a remedial action that will limit
the use of and access to the impacted soil, cap the site with
the addition of a clay fill and geosynthetic liner, and
groundwater monitoring for a period of up to 30 years. The
estimated cost of the proposed remedial action is
$1.5 million, which is comprised primarily of operating and
maintenance costs that would be associated with a groundwater
monitoring project. The Tennessee Regulatory Authority granted
us permission to defer, until our next rate case in Tennessee,
all costs incurred in Tennessee in connection with state and
federally mandated environmental control requirements.
In March 2002, the TDEC contacted us about
conducting an investigation at a former manufactured gas plant
located in Bristol, Tennessee. We agreed to perform a
preliminary investigation at the site, which we completed in
June 2002. The investigation identified manufactured gas plant
residual materials in the soil beneath the site, and we have
proposed performing a focused removal action to remove any such
residuals. The TDEC has requested that the focused removal
action be conducted pursuant to a voluntary agreement. On
April 13, 2004, we entered into a voluntary consent
agreement with the TDEC for the performance of the removal
action and anticipate completing such removal action later this
year.
On July 22, 1998, we entered into an
Abatement Order on Consent with the Missouri Department of
Natural Resources to address the former manufactured gas plant
located in Hannibal, Missouri. We agreed to perform a removal
action and a subsequent site evaluation and to reimburse the
response costs incurred by the
20
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
state of Missouri in connection with the
property. The removal action was conducted and completed in
August 1998, and the site-evaluation field work was conducted in
August 1999. A risk assessment for the site has been approved by
the Missouri Department of Natural Resources. In preparation for
the risk assessment, we executed and recorded certain site-use
limitations, including restricting use of the site to commercial
and industrial purposes and prohibiting the withdrawal of
groundwater for use as drinking water. In addition, we intend to
grade the site and install a geosynthetic liner over the surface
of the site by the end of calendar 2004.
In 1995, United Cities Gas Company entered into
an agreement with a third party to resolve its share of the
costs of additional investigations and environmental-response
actions for soil contamination at a former manufactured gas
plant in Keokuk, Iowa. However, the extent of groundwater
contamination at the site, if any, which is not covered by the
agreement, has yet to be determined.
As of June 30, 2004, we had incurred costs
of approximately $1.7 million for the investigations of the
Johnson City and Bristol, Tennessee, and Hannibal, Missouri,
sites and had a remaining accrual relating to these sites of
$0.2 million, which is recorded as a component of other
current liabilities.
We are a party to other environmental matters and
claims that arise out of our ordinary business. While the
ultimate results of response actions to these environmental
matters and claims cannot be predicted with certainty, we
believe the final outcome of such response actions will not have
a material adverse effect on our financial condition, results of
operations or net cash flows because we believe that the
expenditures related to such response actions will be recovered
through rates, shared with other parties or adequately covered
by insurance.
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, 2004, AEM
is committed to purchase 48.8 Bcf within one year and
1.1 Bcf within one to three years under indexed contracts.
AEM is committed to purchase 0.6 Bcf within one year under
fixed-price contracts, with prices ranging from $4.08 to $6.47.
Purchases under these contracts totaled $283.5 million and
$320.0 million for the three months ended June 30,
2004 and 2003 and $981.5 and $1,118.6 million for the nine
months ended June 30, 2004 and 2003.
Our utility segment maintains supply contracts
with several vendors, generally for 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.
During fiscal 2003, the Internal Revenue Service
initiated a routine examination of our fiscal 1999, 2000 and
2001 tax returns. We believe all material tax items have been
accrued related to the years under audit.
Credit risk is the risk of financial loss to us
if a customer fails to perform its contractual obligations. We
engage in transactions for the purchase and sale of products and
services with major companies in the energy industry and with
industrial, commercial, residential and municipal energy
consumers. These transactions principally occur in the southern
and midwestern regions of the United States. We believe that
this geographic concentration does not contribute significantly
to our overall exposure to credit risk. Credit risk associated
with trade accounts receivable for the utility segment is
mitigated by the large number of individual customers and
diversity in customer base. Due to minimal receivables, the
credit risk for our other nonutility segment is not significant.
21
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
This diversification in AEM’s customers
helps mitigate its credit exposure. AEM maintains credit
policies with respect to its counterparties that it believes
minimizes overall credit risk. Where appropriate, such policies
include the evaluation of a prospective counterparty’s
financial condition, collateral requirements and the use of
standardized agreements that facilitate the netting of cash
flows associated with a single counterparty. AEM also monitors
the financial condition of existing counterparties on an ongoing
basis. Customers not meeting minimum standards are required to
provide adequate assurance of financial performance.
AEM maintains a provision for credit losses based
upon factors surrounding the credit risk of customers,
historical trends and other information. We believe, based on
our credit policies and our provisions for credit losses, that
our financial position, results of operations and cash flows
will not be materially affected as a result of counterparty
nonperformance.
AEM’s estimated credit exposure is monitored
in terms of the percentage of its customers that are rated as
investment grade versus non-investment grade. Credit exposure is
defined as the total of (1) accounts receivable,
(2) delivered, but unbilled physical sales and
(3) mark-to-market exposure for sales and purchases.
Investment grade determinations are set internally by the credit
department, but are primarily based on external ratings provided
by Moody’s Investor Service Inc. and/or Standard &
Poor’s Rating Service, a Division of the McGraw-Hill
Companies, Inc. For non-rated entities, the default rating for
municipalities is investment grade, while the default rating for
non-guaranteed industrials and commercials is non-investment
grade. The table below shows the percentages related to the
investment ratings as of June 30, 2004 and
September 30, 2003. As indicated below, a majority of
AEM’s customers are rated as investment grade.
The following table presents our derivative
counterparty credit exposure by operating segment based upon the
unrealized fair value of our derivative contracts that represent
assets as of June 30, 2004. Investment grade counterparties
have minimum credit ratings of BBB-, assigned by
Standard & Poor’s Rating Group; or Baa3, assigned
by Moody’s Investor Service. Non-investment grade
counterparties are composed of counterparties that are below
investment grade or that have not been assigned an internal
investment grade rating due to the short-term nature of the
contracts associated with that counterparty. This category is
composed of numerous smaller counterparties, none of which is
individually significant.
22
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Atmos Energy Corporation and its subsidiaries are
engaged primarily in the natural gas utility business as well as
certain nonutility businesses. We distribute natural gas through
sales and transportation arrangements to approximately
1.7 million residential, commercial, public-authority and
industrial customers through our six regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses, we provide
natural gas management and marketing services to industrial
customers, municipalities and other local distribution companies
located in 18 states. Finally, we construct electric
power-generating plants and associated facilities to meet peak
load demands and lease or sell them to municipalities and
industrial customers.
Our operations are divided into three segments:
Our determination of reportable segments
considers the strategic operating units under which we manage
sales of various products and services to customers in differing
regulatory environments. The accounting policies of the segments
are the same as those described in Note 2 to our Annual
Report on Form 10-K for the year ended September 30,
2003. We evaluate performance based on net income or loss of the
respective operating units. Summarized income statements by
segment are shown in the following tables.
23
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
24
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
25
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Balance sheet information at June 30, 2004
and September 30, 2003, by segment, is presented in the
following tables:
26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
(1)
Acquired in December 2002.
(2)
Denotes locations where we have more limited
service areas.
2.
Unaudited Interim Financial
Information
Significant Accounting
Policies
Stock-based Compensation
Plans
Regulatory Assets and
Liabilities
Comprehensive Income
Three Months Ended
Nine Months Ended
June 30
June 30
2004
2003
2004
2003
(In thousands)
$
4,765
$
(201
)
$
92,611
$
74,124
(441
)
1,318
1,067
519
1,353
—
1,353
—
(4,377
)
—
(4,377
)
—
$
1,300
$
1,117
$
90,654
$
74,643
Recent Accounting
Developments
TXU Gas Company
ComFurT Gas Inc.
4.
Goodwill and Intangible Assets
June 30,
September 30,
2004
2003
(In thousands)
$
271,467
$
268,469
4,377
5,030
$
275,844
$
273,499
5.
Derivative Instruments and Hedging
Activities
Utility Hedging Activities
Nonutility Hedging Activities
Treasury Activities
6.
Debt
Long-Term Debt
June 30,
September 30,
2004
2003
(In thousands)
$
2,303
$
2,303
350,000
350,000
250,000
250,000
10,000
10,000
10,000
10,000
150,000
150,000
17,000
17,000
11,250
13,750
16,000
17,000
—
2,160
18,000
18,000
20,000
20,000
4,167
6,733
10,464
6,317
869,184
873,263
(5,918
)
(9,345
)
$
863,266
$
863,918
Short-Term Debt
Committed Credit Facilities
Uncommitted Credit Facilities
7.
Earnings Per Share
8.
Interim Pension and Other Postretirement
Benefit Plan Information
Pension Benefits
Other Benefits
2004
2003
2004
2003
6.00%
6.00%
6.00%
6.00%
4.00%
4.00%
4.00%
4.00%
9.00%
9.00%
5.30%
5.30%
9.
Commitments and Contingencies
Litigation
Colorado-Kansas Division
Texas Division
United Cities Propane Gas, Inc.
Environmental Matters
Manufactured Gas Plant Sites
Purchase Commitments
Other
10.
Concentration of Credit Risk
June 30,
September 30,
2004
2003
53%
59%
47%
41%
100%
100%
(1)
Counterparty risk for our utility segment is
minimized because hedging gains and losses are passed through to
our customers.
11.
Segment Information
•
The utility segment, which includes our regulated
natural gas distribution and sales operations,
•
The natural gas marketing segment, which includes
a variety of natural gas management services and
•
The other nonutility segment, which includes all
of our other nonutility operations.
For the Three Months Ended June 30, 2003
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
245,741
$
240,760
$
1,969
$
—
$
488,470
257
134,072
1,716
(136,045
)
—
245,998
374,832
3,685
(136,045
)
488,470
161,426
367,395
467
(135,882
)
393,406
84,572
7,437
3,218
(163
)
95,064
78,306
1,375
1,490
(163
)
81,008
6,266
6,062
1,728
—
14,056
1,347
430
662
(1,753
)
686
16,235
662
898
(1,753
)
16,042
(8,622
)
5,830
1,492
—
(1,300
)
(4,005
)
2,314
592
—
(1,099
)
$
(4,617
)
$
3,516
$
900
$
—
$
(201
)
For the Nine Months Ended June 30, 2003
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
1,341,558
$
1,013,426
$
8,060
$
—
$
2,363,044
969
325,306
8,182
(334,457
)
—
1,342,527
1,338,732
16,242
(334,457
)
2,363,044
934,649
1,325,655
1,475
(333,933
)
1,927,846
407,878
13,077
14,767
(524
)
435,198
248,485
7,366
5,313
(524
)
260,640
159,393
5,711
9,454
—
174,558
(872
)
1,703
6,067
(3,577
)
3,321
47,231
2,090
1,935
(3,577
)
47,679
111,290
5,324
13,586
—
130,200
40,796
2,114
5,393
—
48,303
70,494
3,210
8,193
—
81,897
—
(7,773
)
—
—
(7,773
)
$
70,494
$
(4,563
)
$
8,193
$
—
$
74,124
At June 30, 2004
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
ASSETS
$
1,631,190
$
7,981
$
45,575
$
—
$
1,684,746
156,428
(1,413
)
—
(155,015
)
—
108,758
17,263
874
—
126,895
789
13,136
—
(4,372
)
9,553
164,163
187,366
33,623
(42,135
)
343,017
—
—
12,781
(12,781
)
—
273,710
217,765
47,278
(59,288
)
479,465
—
4,377
—
—
4,377
237,635
21,704
12,128
—
271,467
—
905
—
(173
)
732
214,724
1,777
23,244
—
239,745
$
2,513,687
$
253,096
$
128,225
$
(214,476
)
$
2,680,532
CAPITALIZATION AND LIABILITIES
$
926,846
$
90,666
$
65,762
$
(156,428
)
$
926,846
854,803
—
8,463
—
863,266
1,781,649
90,666
74,225
(156,428
)
1,790,112
3,917
—
2,001
—
5,918
—
—
—
—
—
8,227
12,370
—
(4,967
)
15,630
256,430
146,552
32,732
(39,462
)
396,252
4,081
8,700
—
(12,781
)
—
272,655
167,622
34,733
(57,210
)
417,800
225,632
(8,669
)
11,080
(144
)
227,899
—
2,292
—
(694
)
1,598
105,059
—
—
—
105,059
128,692
1,185
8,187
—
138,064
$
2,513,687
$
253,096
$
128,225
$
(214,476
)
$
2,680,532
At September 30, 2003
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
ASSETS
$
1,555,381
$
9,288
$
59,725
$
—
$
1,624,394
133,586
(2,662
)
—
(130,924
)
—
—
14,880
803
—
15,683
202
22,941
—
(884
)
22,259
230,609
197,239
85,119
(92,912
)
420,055
114,550
—
—
(114,550
)
—
345,361
235,060