SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported)DECEMBER 22, 1993
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ATMOS ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
TEXAS 1-10042 75-1743247
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(State or other (Commission File No.) (IRS Employer ID. No.)
jurisdiction of
incorporation)
1800 THREE LINCOLN CENTRE, 5430 LBJ FREEWAY, DALLAS, TEXAS 75240
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(Address of principal executive offices) (Zip
Code)
Registrant's telephone number, including area code (214) 934-9227
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(Former name or former address, if changed since last report)<PAGE>
ITEM 5. OTHER EVENTS
In December 1993, Atmos Energy Corporation ("Atmos" or the
"Company") acquired Greeley Gas Company ("GGC") of Denver, Colo-
rado in a merger transaction accounted for as a pooling of inter-
ests. The transaction was structured to be a tax-free reorgani-
zation. The Company exchanged 2,329,330 shares of its common
stock before the 3-for-2 stock split, effected in the form of a
stock dividend, which occurred in May 1994 (3,493,995 shares on a
post-split basis) for all of the outstanding stock of GGC. The
Greeley Gas Division was previously a privately held company and
provides natural gas service to nearly 100,000 customers in
approximately 122 communities in Colorado, Kansas and a small
service area in Missouri. For further information regarding the
merger and the stock split, see Notes 2 and 5, respectively, of
the accompanying notes to consolidated financial statements.
The following financial information of Atmos Energy Corpora-
tion is included herein and has been restated to include the
operations of GGC for all periods presented under the pooling of
interests accounting method and has been adjusted for Atmos' 3-
for-2 stock split, effected in the form of a stock dividend, in
May 1994.
Management's discussion and analysis of financial condition
and results of operations for the three years ended September
30, 1993
Independent auditors' report
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 1993 and
1992
Consolidated statements of income for the years ended
September 30, 1993, 1992 and 1991
Consolidated statements of shareholders' equity for the
years ended September 30, 1993, 1992 and 1991
Consolidated statements of cash flows for the years ended
September 30, 1993, 1992 and 1991
Notes to consolidated financial statements
Supplementary data (unaudited)
Financial statement schedules for the years ended September 30,
1993, 1992 and 1991:
V - Property, plant and equipment
VI - Accumulated depreciation and amortization of
property, plant and equipment
2<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
The Company distributes and sells natural gas to residen-
tial, commercial, industrial and agricultural customers in six
states. Such business is subject to federal and state regulation
and/or regulation by local authorities in each of the states in
which the Company operates. In addition, the Company's business
is affected by seasonal weather patterns, competitive factors
within the energy industry, and economic conditions in the areas
that the Company serves.
ACQUISITION OF GREELEY GAS COMPANY THROUGH MERGER
The Company has expanded its customer base and sought to
diversify the regulations, weather patterns and local economic
conditions to which it is subject through acquisitions in 1986
and 1987. The Company continues to consider and pursue, where
appropriate, additional acquisitions of natural gas distribution
properties and other business opportunities, including municipal
systems near existing service areas, as well as agreements to
operate systems for municipalities.
In December 1993, the Company acquired Greeley Gas Company
("GGC") of Denver, Colorado in a merger transaction accounted for
as a pooling of interests; therefore, all historical financial
statements and notes thereto have been restated to retroactively
reflect this merger. The Greeley Gas Division, which was previ-
ously a privately held company, provides natural gas service to
nearly 100,000 customers in approximately 122 communities in
Colorado, Kansas and a small service area in Missouri. The
transaction was structured to be a tax-free reorganization. The
Company exchanged 2,329,330 shares of its common stock before the
3-for-2 stock split (3,493,995 shares on a post-split basis) for
all of the outstanding stock of GGC. Approximately $.5 million
of expenses related to the merger was recognized by the Company
in fiscal 1993. An additional $1.0 million to $2.0 million will
be recognized in fiscal 1994. For further information regarding
the merger, see Note 2 of notes to consolidated financial state-
ments.
The Company believes that, while the merger may result in
some dilution during the short term, it is expected to be non-
dilutive over the long term with respect to earnings per share.
The Company believes this transaction is consistent with its
continuing long-term corporate development strategy of increasing
the value of the Company through external growth. The Company
believes this acquisition will help to further diversify both the
geographic scope of its markets and the mix of its customer
profile, thereby reducing its exposure to changes in the economic
conditions in any given segment of its service area and will add
to diversification in the areas of weather, regulatory environ-
ment, and economic environment. Over the longer term, the Com-
pany expects this combination to contribute to the stability and
predictability of earnings and cash flow.
3<PAGE>
RATE ACTIVITY
The Company filed for a rate increase with the Kentucky
Public Service Commission (the "Kentucky Commission") for its
Western Kentucky Gas Company service area (the "Western Kentucky
Division") in February 1990. The proposed rates would have
produced approximately $8.9 million per year in additional reve-
nues, or an overall increase of approximately 8.0% for the West-
ern Kentucky Division. On September 13, 1990, the Kentucky
Commission issued an Order establishing rates that would increase
annual revenues approximately $1.0 million, or approximately 1%
for the Western Kentucky Division. The Company implemented the
rates in accordance with the Order and filed a motion for rehear-
ing on certain issues. On May 29, 1991 the Kentucky Commission
issued an Order on Rehearing increasing allowed revenues an
additional $2.6 million resulting in a total combined revenue
increase of $3.6 million. The new rates were effective as of the
date of the Order on Rehearing. In June 1991, the Kentucky
Attorney General's office and the Company each filed appeals of
certain issues contained in the Kentucky Commission's Order on
Rehearing with the Franklin County, Kentucky Circuit Court. The
Attorney General's suit was dismissed. In June 1993, the Circuit
Court affirmed the Kentucky Commission's Order and denied relief
to the Company. The Company's case has been appealed to the
Kentucky Court of Appeals. The Company filed a Notice of Appeal
in July 1993, and is awaiting action by the court. The Company's
appeal in Kentucky relates solely to the determination of the
appropriate effective date of its last rate increase in Kentucky.
The Kentucky Public Service Commission made the increase effec-
tive in May 1991, while the Company believes it should have
become effective in September 1990. The Company lost the issue
at the trial court level. If the Company is successful, it could
recover approximately $1 million in additional revenue; if it is
unsuccessful, there would be no impact on its revenue.
In April 1991, the Company filed to increase revenues by
approximately $6.0 million for a portion of its Energas Company
service area ("Energas Division"). The proposed rates would have
produced an overall increase of approximately 6.0% of current
annual revenues generated from approximately 211,000 customers.
The Company entered into a settlement with the rate-setting
authorities in the affected cities which granted approximately
$4.6 million in additional annual revenues. The increase was
implemented in the cities on September 1, 1991 and in the envi-
rons outside the cities on October 1, 1991.
During the period of 1991 through 1993, the Company also
filed for and received small rate increases in certain other rate
jurisdictions in its Energas Division totaling approximately $.3
million annually.
The Company filed for a rate increase with the Louisiana
Public Service Commission (the "Louisiana Commission") in Novem-
ber 1991 for its Louisiana service area ("Trans La Division").
The proposed rates would produce approximately $3.4 million per
year in additional revenues, or an overall increase of approxi-
mately 9.8% for the Trans La Division. Effective September 3,
4<PAGE>
1992, the Louisiana Commission granted an increase of approxi-
mately $1.0 million per year in additional revenues, or an over-
all increase of approximately 2.8%. The rate order also allows
the Company to collect franchise taxes as a line item on the
Company's bills which will reduce taxes, other than income taxes,
by approximately $800,000 per year. The rate order also approves
a rate stabilization clause for three years that provides for an
annual adjustment to the Company's rates to reflect changes in
expenses, revenues and invested capital following an annual
review. The rate stabilization clause provides an opportunity
for a return on jurisdictional common equity of between 11.75%
and 12.25%. As a result of the Company's filing under the rate
stabilization clause, an increase of $730,000 annually or 2% went
into effect on March 1, 1993.
On February 11, 1992, the Company filed a rate case with the
city of Amarillo, Texas seeking to increase annual revenues by
approximately $4.4 million, or 12%. The last rate increase in
Amarillo occurred in December 1985 by Order of the Railroad
Commission of Texas ("Railroad Commission"). In June 1992 the
city denied the Company's request for rate relief and the Company
appealed to the Railroad Commission. The Railroad Commission
granted an interim rate increase of approximately $700,000 on an
annual basis, effective from June 10, 1992, which is when the
Company filed its appeal. In November 1992, the Railroad Commis-
sion issued its decision which approved an additional revenue
increase of $1.4 million, resulting in a total annual increase of
$2.1 million. The Company and the city requested a rehearing of
the Order. On January 11, 1993, the Railroad Commission denied
rehearing to both parties. In February 1993, the city appealed
the Railroad Commission's rate order to the District Court of
Travis County, Texas.
In September 1993, GGC filed a request for an increase in
annual revenues of $4.5 million in its Colorado service area
which was pending before the Colorado Public Utility Commission
as of September 30, 1993.
Effective December 1, 1993, GGC received an annual rate
increase of approximately $2.1 million or 10.6% in its Kansas
service area. The settlement included recovery of SFAS No. 106
costs with external funding and a moratorium on rate requests in
Kansas until December 1, 1996.
In 1992 the Federal Energy Regulatory Commission ("FERC")
issued an order ("Order 636") which continues past FERC initia-
tives to substantially restructure the interstate natural gas
pipeline industry by unbundling the availability and pricing of
interstate pipeline services. Order 636 requires pipelines to
offer nondiscriminatory transportation service comparable with
traditional service provided under city gate sales service. The
Western Kentucky Division will be the most affected by Order 636
since its interstate pipeline suppliers provided a bundled mer-
chant service during fiscal 1993, which they will no longer
provide after they implement Order 636. The Company has been
actively participating in the restructuring proceedings of the
two primary interstate pipelines that serve its Western Kentucky
Division. New service agreements became effective in September
5<PAGE>
and November 1993 with Tennessee Gas and Texas Gas, respectively.
The Company believes it has procured supplies of natural gas and
pipeline services under Order 636 that will replace the tradi-
tional pipeline sales service and enable it to continue to pro-
vide adequate and reliable service to its customers in 1994.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED
As of September 30, 1993, the Company had not adopted State-
ment of Financial Accounting Standards No. 109, "Accounting for
Income Taxes". See Note 4 of notes to consolidated financial
statements. The Company believes that the adoption of a liabil-
ity approach to accounting for income taxes will not have a
material impact on its financial condition or results of opera-
tions, absent a material change in the statutory federal income
tax rate.
As of September 30, 1993, the Company had not adopted State-
ment of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions".
See Note 6 of notes to consolidated financial statements. The
ultimate impact of the adoption of this standard on the Company's
financial position and results of operations will not be known
with certainty until the standard is adopted and the regulatory
treatment that will be allowed in each of the Company's rate-
making jurisdictions is determined.
The Company has not adopted Statement of Financial Account-
ing Standards No. 112, "Employers' Accounting for Postemployment
Benefits". See Note 6 of notes to consolidated financial state-
ments. The Company does not expect the adoption of this standard
to have a material impact on its financial condition or results
of operations.
RESULTS OF OPERATIONS
YEAR ENDED SEPTEMBER 30, 1993 COMPARED WITH YEAR ENDED SEPTEMBER
30, 1992
Operating revenues increased to $459.6 million in fiscal
1993 from $403.4 million in fiscal 1992 due to colder weather,
increased sales volumes and revenues for every customer type,
rate increases received in Texas and Louisiana, and an increased
number of customers in fiscal 1993. Total sales volumes increas-
ed 9.7 billion cubic feet ("Bcf") to 109.4 Bcf in fiscal 1993, as
compared with fiscal 1992. Average gas revenues per thousand
cubic feet ("Mcf") increased $.16 to $4.02 in fiscal 1993 from
fiscal 1992, while the average cost of gas per Mcf sold increased
$.13 to $2.71. The number of meters in service increased to
636,159 at September 30, 1993 compared with 630,365 at September
30, 1992. Weather was 10% colder in fiscal 1993 than fiscal
1992, and was 2% colder than normal. Because of this colder
weather, sales volumes to weather sensitive residential, commer-
cial and public authority customers increased 5.8 Bcf, or 8%, to
78.0 Bcf in fiscal 1993, as compared with fiscal 1992. Sales
volumes to industrial and agricultural customers increased 3.9
Bcf, or 14%, because of increased irrigation fuel demand in the
Company's West Texas service area. Revenues from gas transported
6<PAGE>
for others increased $1.3 million to approximately $15.0 million
in fiscal 1993. Average transportation fees decreased from $.42
per Mcf to $.38 per Mcf, while transportation volumes increased
7.6 Bcf to 39.8 Bcf in fiscal 1993 as compared with fiscal 1992.
Average transportation fees decreased in fiscal 1993 because of
increased competition for large volume customers in Kentucky.
Gross profit increased by approximately 12% to $163.1 mil-
lion in fiscal 1993 from $146.3 million in fiscal 1992. The
primary factors contributing to the higher gross profit were
increased rates and colder weather, as discussed above. Operat-
ing expenses, excluding income taxes, increased to $122.8 million
in fiscal 1993 from $117.9 million in fiscal 1992 due to in-
creased operating activity. Operation expense increased $3.5
million due to increased distribution expenses, outside services,
wages and benefits expense. Income taxes increased to $10.1
million for fiscal 1993 from $4.8 million for fiscal 1992. The
primary reasons for the increase were higher pre-tax profits and
a higher effective tax rate. The effective tax rate increased
to 36.5% in fiscal 1993 from 30.2% in fiscal 1992 because of
reduced significance of permanent differences due to higher pre-
tax profits and a one percent increase in the statutory rate to
35%, effective January 1, 1993. Operating income increased in
fiscal 1993 by approximately 28% to $30.3 million. The increase
in operating income resulted primarily from increased gross
profit.
Net income increased in fiscal 1993 by approximately 60% to
$17.5 million from $11.0 million in fiscal 1992. This increase
in net income resulted primarily from the increase in operating
income. Also, interest expense decreased $.5 million in fiscal
1993, as compared with fiscal 1992, due to lower weighted average
interest rates. Net income per share increased approximately 53%
to $1.22 for fiscal 1993 compared with fiscal 1992, including the
effects of an increase in average shares outstanding of approxi-
mately 4%.
The Atmos pension obligations were computed as of June 30,
1993, using a discount rate of 7.75%. If the obligations had
been calculated using September 30, 1993 as the measurement date,
it is likely that the discount rate used would have been somewhat
lower. Assuming a discount rate of 7%, the accumulated benefit
obligation for the qualified plans would increase approximately
$12.0 million. However, the plan assets would still be in excess
of the accumulated benefit obligation, thus creating no addi-
tional liability under the plans. An additional liability of
approximately $1.4 million would be recognized for the supplemen-
tal plans. Net periodic pension cost for fiscal 1994 would be
increased by approximately $1.0 million and $.3 million for the
qualified plans and supplemental plans, respectively. These are
broad estimates of the impact of a .75% change in discount rate.
YEAR ENDED SEPTEMBER 30, 1992 COMPARED WITH YEAR ENDED SEPTEMBER
30, 1991
Operating revenues increased to $403.4 million in fiscal
1992 from $399.7 million in fiscal 1991 due to rate increases
received in Texas and Kentucky in 1991, an increased number of
7<PAGE>
customers in fiscal 1992 and increased volumes sold to residen-
tial customers in fiscal 1992. Average gas revenues per Mcf
increased $.12 to $3.86 in fiscal 1992 from fiscal 1991, while
the average cost of gas per Mcf sold was unchanged at $2.58. The
number of meters in service increased to 630,365 at September 30,
1992 compared with 619,111 at September 30, 1991. Although the
weather was 3% colder in fiscal 1992 than fiscal 1991, it re-
mained 7.7% warmer than normal. Also, the Company's West Texas
service area experienced unusually cool, wet weather during the
spring and summer months. As a result, sales to residential
customers increased .7 Bcf in fiscal 1992, but sales to indus-
trial and agricultural customers decreased 2.3 Bcf because of
lower irrigation fuel demand in the Company's West Texas service
area. Total sales volumes decreased 1.7 Bcf to 99.7 Bcf in fiscal
1992, as compared with fiscal 1991. Revenues from gas trans-
ported for others decreased $2.7 million to approximately $13.7
million in fiscal 1992 due to lower transportation fees and
volumes. Volumes transported decreased 3.0 Bcf to 32.2 Bcf in
fiscal 1992.
Gross profit increased by approximately 6% to $146.3 million
in fiscal 1992 from $137.9 million in fiscal 1991. The primary
factors contributing to the higher gross profit were increased
prices and slightly cooler weather, as discussed above. Operat-
ing expenses, excluding income taxes, increased to $117.9 million
in fiscal 1992 from $111.5 million in fiscal 1991 due to in-
creased operation expense, depreciation and taxes other than
income taxes. Operation expense increased $4.5 million due in
part to increased wages and benefits expense. Income taxes
increased to $4.8 million for fiscal 1992 from $3.7 million for
fiscal 1991, before reinstatement of $1.1 million of deferred
taxes for GGC in 1991. (See Note 2 of notes to consolidated
financial statements.) The primary reasons for the increase were
higher pre-tax profits and a higher effective tax rate. The
effective tax rate increased to 30.2% in fiscal 1992 from 25.8%
in fiscal 1991 due to higher pre-tax profits taxed at the statu-
tory rate of 34%, higher state income taxes and a smaller impact
from permanent differences in fiscal 1992. Operating income
increased in fiscal 1992 by approximately 4% to $23.6 million
from $22.6 million in fiscal 1991. The increase in operating
income resulted primarily from increased gross profit.
Net income increased in fiscal 1992 by approximately 14% to
$11.0 million from $9.6 million in the prior fiscal year. This
increase in net income resulted primarily from an increase in
operating income, which was partially offset by an increase in
interest expense. Net income per share increased to $.80 for
fiscal 1992 from $.71 for fiscal 1991, including the effects of
an increase in average shares outstanding of approximately 2%.
CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of
Cash Flows")
Cash Flows from Operating Activities
Cash flows from operating activities totaled $37.1 million
for fiscal 1993 compared with $31.4 million for fiscal 1992.
The substantial increase in net income in fiscal 1993 was par-
8<PAGE>
tially offset by the net changes in assets and liabilities. Gas
stored underground increased because the Company secured off-
system storage with a pipeline company in 1993 in compliance with
the pipeline company's Order 636 implementation. The $10.9
million increase in deferred charges and other assets relates to
the $8.4 million increase in deferred credits and other liabili-
ties and recognizes funding for the Supplemental Executive Bene-
fits Plan. See "Consolidated Statements of Cash Flows" for other
changes in assets and liabilities.
Cash Flows from Investing Activities
Net cash used in investing activities totaled $42.2 million
compared with $39.5 million in fiscal 1992 and $34.2 million in
fiscal 1991. Capital expenditures in fiscal 1993 amounted to
$43.1 million compared with $42.2 million in fiscal 1992 and
$37.6 million in fiscal 1991. Currently budgeted capital expend-
itures for fiscal 1994 total $50.6 million and include major
expenditures for mains, services, meters, vehicles and computer
software. Such expenditures will be financed from internally
generated funds and financing activities, as discussed below.
Cash Flows from Financing Activities
Net cash provided by financing activities totaled $3.7
million for fiscal 1993 compared with $8.3 million for fiscal
1992 and $8.6 million in fiscal 1991. Financing activities
during these periods included issuance of common stock, dividend
payments, borrowings from banks, and issuance and repayments of
long-term debt.
Cash dividends and distributions paid. The Company paid
$10.2 million in cash dividends and distributions during fiscal
1993. The $1.2 million increase over fiscal 1992 primarily
reflects a $.005 per share increase in the Company's quarterly
dividend rate and an increase in the number of shares of common
stock outstanding in fiscal 1993. The Company has increased its
dividend in each of the last five years. The amounts included in
this caption also include GGC's cash distributions to its S
corporation shareholders prior to the merger in December 1993.
Short-term financing activities. At September 30, 1993, the
Company had committed lines of credit totaling $72.0 million, of
which $62.0 million was unused, in order to provide for short-
term cash requirements. These credit facilities are negotiated
at least annually. At September 30, 1993, the Company also had
uncommitted short-term credit lines of $114.0 million, of which
$88.3 million was unused. During fiscal 1993, notes payable
increased $2.6 million compared with $18.6 million during fiscal
1992. The lower increase in short-term borrowing in fiscal 1993
compared with fiscal 1992 was due to increased funds provided by
operations and stock issued under the Direct Stock Purchase Plan.
In 1991 notes payable to banks decreased by $16.5 million. The
decrease was primarily due to the issuance of long-term debt in
1991.
Long-term financing activities. Scheduled payments of long-
term debt in fiscal 1993 consisted of a $3.5 million installment
9<PAGE>
on the Company's 9.75% Senior Notes and a $1.0 million payment on
the 13.75% Series I First Mortgage Bonds. No long-term debt was
issued in fiscal 1993. The Company entered into an agreement
with an insurance company in August 1992, for a private placement
of $10.0 million of unsecured Senior Notes due in annual install-
ments of $1.0 million from 1997 through 2006, with interest to be
paid semiannually at 7.95%. The net proceeds from the sale of
the Senior Notes were used primarily to refinance an 8.4% note in
the amount of $9.8 million. The Company also made scheduled
installments of $4.5 million on its 9.75% Senior Notes, $1.0
million on the 13.75% Series I First Mortgage Bonds and a $.3
million installment on GGC's 13% Series G First Mortgage Bonds in
fiscal 1992. In September 1991 the Company issued $20.0 million
of its 9.57% Senior Notes to an institutional lender. The pro-
ceeds of the loan were used to repay short-term debt, to avoid
additional borrowing, and for general corporate purposes. During
fiscal 1991, the Company made a scheduled repayment of $5.0
million on its 9.75% Senior Notes. It also made a scheduled
repayment of $1.0 million and a prepayment of $.75 million on its
Series I First Mortgage Bonds. In 1991, GGC issued $17.0 million
of 9.4% Series J First Mortgage Bonds and repaid the balances of
$6.0 million and $1.25 million on its 13.25% series and 12.75%
series, respectively. The loan agreements pursuant to which all
the Company's Senior Notes have been issued contain covenants by
the Company with respect to the maintenance of certain debt-to-
equity ratios and cash flows, and restrictions on the payment of
dividends. Also see Note 3 of notes to consolidated financial
statements.
Issuance of common stock. The Company issued 897,089 and
306,880 shares of common stock in fiscal 1993 and fiscal 1992,
respectively, for its Direct Stock Purchase Plan ("DSPP"), Em-
ployee Stock Ownership Plan and Incentive Stock Option Plan.
The DSPP was implemented in August 1992. The DSPP has been
amended to remove the direct stock purchase feature of the plan
and has been renamed the Atmos Energy Corporation Dividend Rein-
vestment and Stock Purchase Plan ("DRSPP"). In fiscal 1993,
760,089 shares were issued under the plan, generating proceeds of
$13.4 million. Before the 3-for-2 stock split the Company regis-
tered 500,000 shares in March 1993 and registered an additional
700,000 shares during the first quarter of fiscal 1994 to be
reserved and available for issuance under the DRSPP in future
years.
Net proceeds of $10.6 million were provided in fiscal 1991
from the issuance of 1,019,694 shares of common stock. In fiscal
1991, the Company made a public offering of 979,950 shares of
common stock. The net proceeds were used to reduce notes payable
to banks, to avoid additional borrowing, and for general corpo-
rate purposes.
The Company believes that internally generated funds, its
short-term credit facilities and access to the debt and equity
capital markets will provide necessary working capital and li-
quidity for capital expenditures and other cash needs for fiscal
1994.
10<PAGE>
Seasonality
The Company's natural gas distribution business is seasonal
due to weather conditions in the Company's service areas. Gas
sales are affected by winter heating season requirements, and
sales to agricultural customers (who use natural gas as fuel in
the operation of irrigation pumps and other equipment) during the
period from April through September may be affected by rainfall
amounts. These factors generally result in higher operating
revenues and net income during the period from October through
March of each year and lower operating revenues and either net
losses or lower net income during the period from April through
September of each year.
The following table sets forth, on an unaudited basis, the
Company's quarterly operating revenues, quarterly operating
revenues as a percentage of annual operating revenues, quarterly
net income (loss) and quarterly net income (loss) as a percentage
of annual net income for its past two fiscal years.
<TABLE>
<CAPTION>
Quarter ended
---------------------------------------------------
Year ended September 30, December 31 March 31 June 30 September 30 Total
------------------------ ------------ --------- -------- ------------ ----------
(In thousands, except for percentages)
1993
----
<C> <C> <C> <C> <C> <C>
Operating revenues $130,700 $166,238 $91,219 $71,484 $459,641
28% 36% 20% 16% 100%
Net income (loss) $ 6,764 $ 13,760 $ 830 $(3,810) $ 17,544
39% 78% 5% (22)% 100%
1992
----
Operating revenues $125,058 $140,327 $70,780 $67,188 $403,353
31% 35% 17% 17% 100%
Net income (loss) $ 5,686 $ 10,464 $(1,627) $(3,525) $ 10,998
52% 95% (15)% (32)% 100%
</TABLE>
Inflation
The Company believes that inflation has caused increases in
certain operating expenses and has required assets to be replaced
at costs that are higher than original costs. The Company con-
tinually reviews the adequacy of its gas rates in relation to the
increasing cost of providing service.
Environmental Matters
From time to time, the Company receives inquiries regarding
various environmental matters. The Company believes that its
properties and operations substantially comply with and are
operated in substantial conformity with all applicable environ-
mental statutes and regulations. There are no administrative or
judicial proceedings arising under environmental quality statutes
pending or known to be contemplated by governmental agencies
which, if adversely determined, would have a material adverse
effect on the Company.
11<PAGE>
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Ernst & Young, independent auditors
Consolidated balance sheets
Consolidated statements of income
Consolidated statements of shareholders' equity
Consolidated statements of cash flows
Notes to consolidated financial statements
Supplementary data (unaudited)
12<PAGE>
REPORT OF ERNST & YOUNG,
INDEPENDENT AUDITORS
Board of Directors
Atmos Energy Corporation
We have audited the accompanying consolidated balance sheets
of Atmos Energy Corporation at September 30, 1993 and 1992, and
the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period
ended September 30, 1993. Our audits also included the financial
statement schedules listed in Item 5. These financial state-
ments and schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements and schedules based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstate-
ment. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial state-
ments. An audit also includes assessing the accounting princi-
ples used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opin-
ion.
In our opinion, the consolidated financial statements re-
ferred to above present fairly, in all material respects, the
consolidated financial position of Atmos Energy Corporation at
September 30, 1993 and 1992, and its consolidated results of
operations and its cash flows for each of the three years in the
period ended September 30, 1993 in conformity with generally
accepted accounting principles. Also, in our opinion, the re-
lated financial statement schedules, when considered in relation
to the basic financial statements taken as a whole, present
fairly in all material respects the information set forth
therein.
ERNST & YOUNG
Dallas, Texas
November 10, 1993, except for
Notes 2 and 5, as to which the date
is February 9, 1994
13 <PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS September 30,
--------------------
1993 1992
-------- --------
ASSETS (In thousands, except share data)
Property, plant and equipment
Utility plant $496,153 $458,548
Construction in progress 5,359 4,065
-------- --------
501,512 462,613
Less accumulated depreciation and
amortization 202,237 185,689
-------- --------
Net property, plant and equipment 299,275 276,924
Current assets
Cash and cash equivalents 2,286 3,699
Accounts receivable, less allowance for
doubtful accounts of $963 in 1993
and $880 in 1992 29,200 30,764
Inventories 6,064 6,772
Gas stored underground 17,603 11,427
Prepayments 4,240 6,113
-------- --------
Total current assets 59,393 58,775
Deferred charges and other assets 32,950 22,664
-------- --------
$391,618 $358,363
CAPITALIZATION AND LIABILITIES ======== ========
Shareholders' equity
Common stock, no par value (stated at $.005
per share); authorized 50,000,000 shares;
issued and outstanding 1993 - 14,868,902
shares, 1992 - 13,971,813 shares $ 74 $ 70
Additional paid-in capital 94,279 78,541
Retained earnings 45,076 38,637
-------- --------
Total shareholders' equity 139,429 117,248
Long-term debt 105,853 112,153
-------- --------
Total capitalization 245,282 229,401
Current liabilities
Current maturities of long-term debt 6,300 4,500
Notes payable to banks 35,700 32,600
Accounts payable 27,803 27,861
Taxes payable 3,797 4,251
Customers' deposits 7,862 7,923
Other current liabilities 6,455 5,188
-------- --------
Total current liabilities 87,917 82,323
Deferred income taxes 32,614 29,232
Deferred credits and other liabilities 25,805 17,407
-------- --------
$391,618 $358,363
======== ========
See accompanying notes to consolidated financial statements.
14<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended September 30,
-------------------------------------
1993 1992 1991
--------- -------- --------
(In thousands, except per share data)
Operating revenues $459,641 $403,353 $399,667
Purchased gas cost 296,532 257,091 261,796
--------- --------- ---------
Gross profit 163,109 146,262 137,871
Operating expenses
Operation 82,185 78,642 74,178
Maintenance 6,335 5,695 6,053
Depreciation and amortization 17,433 17,205 16,020
Taxes, other than income 16,806 16,398 15,294
Income taxes 10,073 4,753 3,721
-------- -------- --------
Total operating expenses 132,832 122,693 115,266
-------- -------- --------
Operating income 30,277 23,569 22,605
Other income (expense)
Interest income 327 376 542
Other, net 239 876 519
-------- -------- --------
Total other income 566 1,252 1,061
Interest charges 13,299 13,823 12,973
-------- -------- --------
Net income before restatement
of income taxes 17,544 10,998 10,693
-------- -------- --------
Reinstatement of deferred
income taxes (Note 2) - - 1,081
-------- -------- --------
Net income $ 17,544 $ 10,998 $ 9,612
======== ======== ========
Net income per share $ 1.22 $ .80 $ .71
======== ======== ========
Cash dividends and distributions
per share $ .71 $ .65 $ .63
======== ======== ========
Average shares outstanding 14,338 13,789 13,486
======== ======== ========
Supplemental net income (Note 2) $ 18,132 $ 10,570 $ 10,130
======== ======== ========
Supplemental net income per share $ 1.26 $ .77 $ .75
======== ======== ========
See accompanying notes to consolidated financial statements.
15<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF
SHAREHOLDERS' EQUITY
Common stock
----------------- Additional
Number of Stated paid-in Retained
shares value capital earnings
--------- ------ ---------- --------
(In thousands, except share data)
Balance at September 30, 1990,
as effected for the 3-for-2
stock split 9,151,244 $ 46 $ 62,840 $ 16,868
Adjustment for pooling of
interests with GGC (Note 2) 3,591,529 18 1,047 20,729
---------- ---- -------- --------
Balance, September 30, 1990,
as restated 12,742,773 64 63,887 37,597
Net income - - - 9,612
Cash dividends - - - (7,919)
GGC distributions - - - (537)
Common stock issued
Dividend reinvestment plan 39,744 - 471 -
Public offering 979,950 4 10,081 -
Retirement of common stock (97,534) - (106) (2,196)
---------- ---- -------- --------
Balance, September 30, 1991 13,664,933 68 74,333 36,557
Net income - - - 10,998
Cash dividends - - - (8,516)
GGC distributions - - - (402)
Common stock issued
Stock option plan 6,750 - 71 -
Direct stock purchase plan 132,249 1 1,849 -
Employee stock ownership 167,881 1 2,288 -
---------- ---- -------- --------
Balance, September 30, 1992 13,971,813 70 78,541 38,637
Net income - - - 17,544
Cash dividends - - - (9,262)
GGC distributions - - - (893)
Common stock issued
Stock option plan 6,000 - 60 -
Direct stock purchase plan 760,089 3 13,401 -
Employee stock ownership 131,000 1 2,277 -
Less: GGC net income for the
quarter ended December 31, 1992 - - - (950)
---------- ---- -------- --------
Balance, September 30, 1993 14,868,902 $ 74 $ 94,279 $ 45,076
========== ==== ======== ========
See accompanying notes to consolidated financial statements.
16<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
1993 1992 1991
-------- ------- -------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $16,594 $10,998 $ 9,612
Adjustments to reconcile net income
to net cash provided by operating
activities
Depreciation and amortization
Charged to depreciation and
amortization 16,480 17,205 16,020
Charged to other accounts 3,377 4,598 4,215
Deferred income taxes 2,733 349 (496)
Other 622 281 196
------- ------- -------
39,806 33,431 29,547
Change in assets and liabilities
(Increase) decrease in accounts
receivable 1,564 (2,202) 1,032
(Increase) decrease in inventories 708 (84) (370)
(Increase) decrease in gas stored
underground (6,176) (14) 784
(Increase) decrease in prepayments 1,873 (287) 1,208
(Increase) decrease in deferred
charges and other assets (10,908) 586 (1,676)
Increase (decrease) in accounts
payable (58) 1,196 (1,253)
Increase in taxes payable 195 930 1,803
Increase (decrease) in customers'
deposits (61) 322 (68)
Increase (decrease) in other current
liabilities 1,804 803 (8,908)
Increase (decrease) in deferred
credits and other liabilities 8,398 (3,269) (1,029)
------- ------- -------
Net cash provided by operating
activities 37,145 31,412 21,070
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (43,143) (42,169) (37,630)
Retirements of property, plant and
equipment 935 2,629 3,399
------- ------- -------
Net cash used in investing
activities (42,208) (39,540) (34,231)
- Continued -
17<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Year ended September 30,
1993 1992 1991
------ ------- -------
(In thousands)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in notes
payable $ 2,563 $18,636 $(16,525)
Proceeds from issuance of long-term
debt - 10,000 37,000
Cash dividends and distributions paid (10,155) (8,918) (8,456)
Repayment of long-term debt (4,500) (15,608) (14,000)
Issuance of common stock 15,742 4,210 10,557
------- ------- -------
Net cash provided by financing
activities 3,650 8,320 8,576
------- ------- -------
Net increase (decrease) in cash and cash
equivalents (1,413) 192 (4,585)
Cash and cash equivalents at beginning
of year 3,699 3,507 8,092
------- ------- -------
Cash and cash equivalents at end
of year $ 2,286 $ 3,699 $ 3,507
======= ======= =======
See accompanying notes to consolidated financial statements.
18<PAGE>
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of significant accounting policies
Description of business - Atmos Energy Corporation and its
subsidiaries (the "Company") are in the business of distributing
natural gas to residential, commercial, industrial and agricul-
tural customers within service areas located in Texas, Louisiana,
Kentucky, Colorado, Kansas and a small portion of Missouri. Such
business is subject to federal and state regulation and/or regu-
lation by local authorities in each of the six states in which
the Company operates. Certain income, expense and capital items
may be treated differently for ratemaking purposes by the regula-
tory authorities. The Company has no other material business
segments.
Principles of consolidation - The accompanying consolidated
financial statements include the accounts of Atmos Energy Corpo-
ration and its subsidiaries. Each subsidiary is wholly-owned and
all material intercompany items have been eliminated.
Revenue recognition - Sales of natural gas are billed on a
monthly cycle basis; however, the billing cycle periods for
certain classes of customers do not necessarily coincide with
accounting periods used for financial reporting purposes. The
Company follows the revenue accrual method of accounting for
natural gas revenues whereby revenues applicable to gas delivered
to customers but not yet billed under the cycle billing method
are estimated and accrued and the related costs are charged to
expense. Estimated losses due to credit risk are reserved at the
time revenue is recognized.
Property, plant and equipment - Property, plant and equip-
ment is stated at original cost net of contributions in aid of
construction. The cost of additions includes an allowance for
funds used during construction and applicable overhead charges.
Major renewals and betterments are capitalized, while the costs
of maintenance and repairs are charged to expense as incurred.
Property, plant and equipment is depreciated at various rates on
a straight-line basis over the estimated useful lives of the
assets. In the first quarter of fiscal 1993, the Company changed
the estimated average useful lives used to compute depreciation
for certain utility plant assets. These changes resulted from
revised estimates of the projected economic life of the affected
assets based on recent orders received from regulatory bodies
having jurisdiction over the Company. The effect of this change
on net income for the year ended September 30, 1993 was an in-
crease of $1,104,000. The composite rates were 3.7% and 4.4% for
the years ended September 30, 1993 and 1992, respectively. At
the time property, plant and equipment is retired, the cost, plus
removal expenses and less salvage, is charged to accumulated
depreciation.
19<PAGE>
Inventories - Inventories consist of materials and supplies
and merchandise held for resale. Inventories are stated at the
lower of average cost or market.
Gas stored underground - Net additions of inventory gas to
underground storage and withdrawals of inventory gas from storage
are priced using the average cost method. Non-current gas in
storage is classified as property, plant and equipment and is
priced at cost.
Income taxes - The Company provides deferred income taxes
for significant timing differences in the recognition of revenues
and expenses for tax and financial reporting purposes.
Cash and cash equivalents - The Company considers all highly
liquid debt instruments purchased with a maturity of three months
or less to be cash equivalents.
Deferred charges and other assets - Deferred charges and
other assets at September 30, 1993 and 1992 include assets of the
Company's qualified defined benefit retirement plans in excess of
the plans' recorded obligations in the amounts of $13,289,000 and
$13,894,000, respectively, and Company assets related to the
nonqualified retirement plans at September 30, 1993 of
$12,758,000.
Deferred credits and other liabilities - Deferred credits
and other liabilities include customer advances for construction
of $7,769,000 and $6,695,000 at September 30, 1993 and 1992,
respectively, and obligations under capital leases of $6,389,000
and $6,585,000 at September 30, 1993 and 1992, respectively, and
obligations under the Company's nonqualified retirement plans of
$8,317,000 at September 30, 1993.
Earnings per share - The calculation of primary earnings per
share is based on reported net income divided by weighted average
common shares outstanding. The Company does not have other
classes of stock or dilutive common stock equivalents.
2. Greeley Gas Company Acquisition
On December 22, 1993, Atmos acquired by means of a merger
all of the assets and liabilities of Greeley Gas Company (GGC) in
accordance with the terms and provisions of an Agreement and Plan
of Reorganization dated July 2, 1993. All of the shares of GGC's
common stock were exchanged for a total of 3,493,995 shares of
Atmos common stock as adjusted for a 3-for-2 stock split
(2,329,330 shares on a pre-split basis). See Note 5. This
merger transaction was accounted for as a pooling of interests;
therefore, all historical financial statements and notes thereto
have been restated to retroactively reflect this merger. Subse-
quent to the merger, the business of GGC has been operated
through the Company's Greeley Gas Company division (the "Greeley
Gas Division").
20<PAGE>
GGC prepared its financial statements on a December 31
fiscal year end. GGC's fiscal year has been changed to September
30 to conform to the Company's year end. The restated September
30, 1993 and 1992 balance sheets, as presented, are the combined
balance sheets of Atmos as of September 30, 1993 and 1992 and GGC
as of September 30, 1993 and December 31, 1992, respectively.
The restated consolidated statements of income and cash flows for
the years ended September 30, 1992 and 1991 include Atmos opera-
tions for the years then ended and GGC operations for the years
ended December 31, 1992 and 1991, respectively. The restated
consolidated statement of income for the year ended September 30,
1993 includes Atmos and GGC operations for the twelve months then
ended. Therefore, since GGC's operations for the three months
ended December 31, 1992 (operating revenue of $18,322,842 and net
income of $950,185) are included in both the 1993 and 1992 re-
stated statements of income, the GGC net income for this period
has been deducted in calculating the shareholders' equity bal-
ances at September 30, 1993 and cash flows for the year then
ended.
In 1987, GGC elected classification as an S Corporation
(small business corporation) under the provisions of the Internal
Revenue Code. Normally, income taxes are not reported in the
financial statements of S Corporations as the liability for
payment of federal and state income taxes is the direct responsi-
bility of the shareholders. However, during 1991, as part of the
settlement of rate cases filed in the states of Colorado and
Kansas, GGC was ordered to begin providing for current and de-
ferred income taxes. Accordingly, the Company's restated 1991
financial statements include a one-time charge to income of
$1,081,202 to reinstate deferred income taxes for GGC. Supple-
mental net income and earnings per share have been presented on
the face of the statement of income to eliminate the one-time
charge and to reflect income tax expense in all periods as if GGC
had not made the S Corporation election in 1987.
Results of operations and net income for the previously
separate companies for periods prior to the merger are as fol-
lows:
1993 1992 1991
Operating revenues -------- -------- --------
Atmos $388,495 $340,117 $336,047
Greeley 71,146 63,236 63,620
-------- -------- --------
$459,641 $403,353 $399,667
======== ======== ========
Net income
Atmos $ 15,712 $ 10,031 $ 7,918
Greeley 1,832 967 1,694
-------- -------- --------
$ 17,544 $ 10,998 $ 9,612
======== ======== ========
GGC is a natural gas utility engaged in the distribution and
sale of natural gas to residential, commercial, industrial,
21<PAGE>
agricultural, and other customers throughout Colorado, Kansas,
and a small portion of Missouri.
3. Long-term debt and notes payable
Long-term debt at September 30, 1993 and 1992 consisted of
the following:
1993 1992
-------- --------
(In thousands)
Unsecured 7.95% Senior Notes, payable
in annual installments of $1,000,000
beginning August 31, 1997 through
August 31, 2006 with semiannual
interest payments $ 10,000 $ 10,000
Unsecured 9.57% Senior Notes, payable
in annual installments of $2,000,000
beginning September 30, 1997 through
September 30, 2006 with semiannual
interest payments 20,000 20,000
Unsecured 9.76% Senior Notes, payable
in annual installments of $3,000,000
beginning December 30, 1995 through
December 30, 2004 with semiannual
interest payments 30,000 30,000
Unsecured 9.75% Senior Notes, payable
in varying annual installments
through December 30, 1996 8,000 11,500
Unsecured 11.2% Senior Notes, payable in
annual installments of $2,000,000
beginning December 30, 1993 through
December 30, 2002 with semiannual
interest payments 20,000 20,000
First Mortgage Bonds, 9.4% series, due
May 1, 2021 17,000 17,000
First Mortgage Bonds, 13% series, due
$300,000 annually, balance of
$1,000,000 due November 1, 1995 1,600 1,600
Unsecured 10% Notes, due December 31,
2011 2,303 2,303
First Mortgage Bonds, 13.75% Series I,
due November 1, 1998, payable in
annual installments of $1,000,000 3,250 4,250
-------- --------
112,153 116,653
Less amounts classified as current (6,300) (4,500)
-------- --------
$105,853 $112,153
======== ========
The Company entered into a note purchase agreement with an
insurance company in August 1992, for a private placement of
$10,000,000 of unsecured Senior Notes at 7.95%. The net proceeds
from the sale of the Senior Notes were used primarily to refi-
nance an 8.4% note in the amount of $9.8 million.
22<PAGE>
On August 29, 1991, the Company entered into a note purchase
agreement with an insurance company to issue at par $20,000,000
of unsecured Senior Notes at 9.57%. The Company issued these
notes on September 30, 1991 and used the proceeds to repay cer-
tain short-term debt.
The Company may prepay any of the Senior Notes in whole at
any time, subject to a prepayment premium. The note agreements
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 September 30, 1988 may not exceed the sum of
75% of accumulated net income for periods after September 30,
1988 plus $12,000,000 plus the proceeds from the sale of common
stock after September 30, 1988. At September 30, 1993, approxi-
mately $42,890,000 of shareholders' equity was not so restricted.
As of September 30, 1993, substantially all of the Company's
utility properties and assets in Kentucky with a book value of
approximately $110,468,000 are subject to a lien under the 13.75%
Series I First Mortgage Bonds which were assumed by the Company
in the purchase of Western Kentucky Gas Utility Corporation
("WKG"). As of September 30, 1993, all of the Company's utility
plant assets in Colorado, Kansas and Missouri with a book value
of approximately $58,300,000 are subject to a lien under the 9.4%
series and 13% series First Mortgage Bonds assumed by the Company
in the acquisition of GGC.
Maturities of long-term debt are as follows:
(In thousands)
1994 $ 6,300
1995 5,300
1996 9,000
1997 9,250
1998 8,000
Thereafter 74,303
--------
$112,153
========
Notes payable to banks -
The Company has committed short-term, unsecured bank credit
facilities totaling $72,000,000, of which $62,000,000 was unused
at September 30, 1993. One facility of $60,000,000 requires a
commitment fee of 1/8 of 1% on the unused portion. A second
facility for $12,000,000 requires a commitment fee of 3/16 of 1%
on the unused portion. The committed lines are renewed or rene-
gotiated at least annually.
23<PAGE>
The Company also had $114,000,000 of uncommitted credit
lines at September 30, 1993. The uncommitted lines have varying
terms and the Company pays no fee for the availability of the
lines. Borrowings under these lines are made on a when and as-
available basis at the discretion of the banks. At September 30,
1993, $88,300,000 was unused.
Information related to notes payable to banks follows:
1993 1992 1991
------- ------- -------
(In thousands, except for percents)
Notes outstanding at September 30 $35,700 $32,600 $13,900
Weighted average interest rate at
September 30 4.1% 4.7% 5.8%
Maximum amount outstanding during
the year $50,300 $36,800 $39,700
Daily average amount outstanding
during the year $19,801 $12,078 $13,106
Weighted average interest rate
during the year computed on a
daily basis 4.2% 5.3% 5.9%
Notes payable to shareholders and employees -
Notes payable to shareholders and employees, amounting to
approximately $537,000 at September 30, 1992, are included in
other current liabilities on the accompanying consolidated bal-
ance sheet. They were for six-month terms and bore interest at
rates ranging from 4.0% to 4.5%. Interest incurred on such notes
aggregated $11,326 and $28,593 for the periods ended September
30, 1993 and 1992, respectively.
4. Income taxes
The components of income tax expense for fiscal 1993, 1992
and 1991 are as follows:
1993 1992 1991
------- ------- -------
(In thousands)
Provision for income taxes
Current $ 7,340 $ 4,653 $ 4,217
Deferred 2,733 100 (496)
------- ------- -------
$10,073 $ 4,753 $ 3,721
======= ======= =======
Included in the provision for income taxes are state income
taxes of $890,000, $403,000 and $357,000 for fiscal 1993, 1992
and 1991, respectively.
24<PAGE>
Deferred income taxes result from timing differences in the
recognition of revenues and expenses for tax and financial re-
porting. The effects of these timing differences for fiscal 1993,
1992 and 1991 are as follows:
1993 1992 1991
------ ----- -----
(In thousands)
Excess of tax over financial
depreciation and amortization $1,754 $ 351 $ 713
Items capitalized for financial
reporting and recognized currently
for tax reporting 416 388 426
Deferred gas service revenue
recognized currently for tax
reporting 1,464 453 (839)
Tax reporting change to the revenue
accrual method of income recognition - - (298)
Other, net (901) (1,092) (498)
------ ----- -----
$2,733 $ 100 $(496)
====== ===== =====
Reconciliations of the provisions for income taxes computed
at the statutory rate to the reported provisions for income taxes
for fiscal 1993, 1992 and 1991 are set forth below:
1993 1992 1991
------ ------ ------
(In thousands)
Tax at statutory rate of 34% through
December 31, 1992 and 35% thereafter $ 9,603 $5,356 $4,901
Financial expenses, not deductible for
tax reporting 680 218 230
Common stock dividends deductible for
tax reporting (462) (446) (402)
Net increase in cash surrender value of
life insurance (181) (210) (151)
State taxes 682 244 116
Other, net (249) (409) (973)
------ ------ ------
Provision for income taxes $10,073 $4,753 $3,721
======= ====== ======
Statement of Financial Accounting Standards No. 109, "Ac-
counting for Income Taxes", issued in February 1992 provides for
a liability approach to accounting for income taxes. Under this
standard, deferred tax liabilities are to be adjusted to the
amount payable in future years at the rate then scheduled to be
in effect. It allows adoption on either a retrospective or
prospective basis. The Company plans to adopt Statement No. 109
on a prospective basis in the first quarter of its fiscal year
ending September 30, 1994. The Company has estimated that the
adoption of a liability approach to accounting for income taxes
25<PAGE>
will not have a material impact on its financial condition or
results of operations, absent a material change in the statutory
federal income tax rate.
5. Stock split
On February 9, 1994, the Board of Directors of Atmos ap-
proved a 3-for-2 split of its common stock implemented in the
form of a stock dividend, which resulted in shareholders receiv-
ing one new share for every two shares held. Fractional shares
were not issued but were paid in cash or credited to the accounts
of participants of the Dividend Reinvestment and Stock Purchase
Plan ("DRSPP") and ESOP. The record date for the split was May
4, 1994 and the payment date for mailing the new shares and cash
for fractional shares to shareholders was May 16, 1994. All
share and per share amounts in the financial statements and notes
thereto have been restated to reflect this split, unless other-
wise noted.
6. Common stock and stock options
The Company issued 897,089 shares of its common stock in
fiscal 1993 in connection with its Direct Stock Purchase Plan,
Incentive Stock Option Plan and Employee Stock Ownership Plan.
The Company has an Employee Stock Ownership Plan as dis-
cussed in Note 6. The Company has registered 600,000 shares
(pre-split) for issuance under the plan, of which 388,212 shares
(pre-split) were available for future issuance on September 30,
1993.
In August 1992 the Company announced a Direct Stock Purchase
Plan ("DSPP") which was the successor to and replacement for the
Dividend Reinvestment Plan ("DRP"). Members of the DRP were
automatically enrolled in the DSPP. In November 1993, the Com-
pany amended the DSPP to remove the direct stock purchase feature
of the plan and to rename the plan the Atmos Energy Corporation
Dividend Reinvestment and Stock Purchase Plan ("DRSPP"). The
DRSPP is now available to shareholders of record only. Partici-
pants in the DRSPP may have all or part of their dividends rein-
vested at a 3% discount from market prices. DRSPP participants
may purchase additional shares of Company common stock as often
as monthly with optional cash payments of at least $25, up to an
annual maximum of $60,000. Purchases of stock under the DRSPP
are made, at the Company's option, either on the open market or
directly from the Company. In March 1993, before the 3-for-2
stock split, the Company registered 500,000 shares to be reserved
for issuance under the predecessor to the DRSPP, of which 128,612
shares (pre-split) were available for future issuance at Septem-
ber 30, 1993. The Company registered an additional 700,000
shares (pre-split) during the first quarter of fiscal 1994 to be
reserved for issuance, at the Company's option, under the DRSPP
in future years.
26<PAGE>
In December 1990, the Company issued 900,000 shares of
common stock for $11.00 per share. In January 1991, the under-
writers exercised their over-allotment option on the stock issue
and purchased an additional 79,950 shares from the Company. The
net proceeds were used to repay the Company's outstanding short-
term debt under two of its credit lines.
On April 27, 1988, the Company adopted a Shareholders'
Rights Plan (the "Rights Plan") and declared a dividend of one
right (a "Right") for each outstanding pre-split share of common
stock of the Company, payable to shareholders of record as of May
10, 1988. Each Right will entitle the holder thereof, until the
earlier of May 10, 1998 or the date of redemption of the Rights,
to buy one share of common stock of the Company at an exercise
price of $45 per share, subject to adjustment by the Board of
Directors upon the occurrence of certain events. The Rights
will be represented by the common stock certificates and are
not exercisable or transferable apart from the common stock
until a "Distribution Date" (which is defined in the Rights
Agreement between the Company and the Rights Agent as the date
upon which the Rights become separate from the common stock).
At no time will the Rights have any voting rights. The
exercise price payable and the number of shares of common stock
or other securities or property issuable upon exercise of the
Rights are subject to adjustment from time to time to prevent
dilution. Until the Distribution Date, the Company will issue
one Right with each share of common stock that becomes outstand-
ing so that all shares of common stock will have attached Rights.
After a Distribution Date, the Company may issue Rights when it
issues common stock if the Board deems such issuance to be neces-
sary or appropriate.
The Rights have certain anti-takeover effects and may cause
substantial dilution to a person or entity that attempts to
acquire the Company on terms not approved by the Board of Direc-
tors except pursuant to an offer conditioned upon a substantial
number of Rights being acquired. The Rights should not interfere
with any merger or other business combination approved by the
Board of Directors because, prior to the time the Rights become
exercisable or transferable, the Rights may be redeemed by the
Company at $.05 per Right.
The Company has had an Incentive Stock Option Plan for key
employees covering an aggregate of 100,000 shares of common
stock. The plan provided for options to be granted at prices not
less than the fair market value of the stock on the date of grant
and to be exercisable over ten years from such date in cumulative
annual installments of 25% of the aggregate shares granted,
commencing one year after the date of grant. At September 30,
1993, no options were outstanding under the plan. Subsequent to
year end, the Company allowed the plan to expire in October 1993
without granting additional options.
27<PAGE>
The following table summarizes the status of the Incentive
Stock Option Plan as of September 30, 1993, 1992 and 1991:
<TABLE>
<CAPTION>
1993 1992 1991
--------------------- -------------------- --------------------
Price Price Price
Shares per share Shares per share Shares per share
------- ----------- ------- ----------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Outstanding options at
beginning of year 6,000 $9.25-10.63 12,750 $9.25-10.63 12,750 $9.25-10.63
Exercised (6,000) 9.25-10.63 (6,750) 9.25-10.63 - -
------- ------ ------
Outstanding options
at end of year - - 6,000 $9.25-10.63 12,750 $9.25-10.63
======= ====== ======
Exercisable options
at end of year - 6,000 12,750
Options available for
future grants (pre-split) 8,150 8,150 8,150
</TABLE>
The Company's Restricted Stock Grant Plan for management and
key employees of the Company, which became effective October 1,
1987, provides for awards of common stock that are subject to
certain restrictions. The plan is administered by the Board of
Directors. The members of the Board who are not employees of the
Company make the final determinations regarding participation in
the plan, awards under the plan, and restrictions on the re-
stricted stock awarded. The restricted stock may consist of
previously issued shares purchased in the open market or shares
purchased directly from the Company. The total number of shares
of restricted stock that may be awarded under the plan was in-
creased to 900,000 shares after receiving shareholder approval in
1993. During fiscal 1993, 1992 and 1991, 25,500, 51,750 and
69,600 shares, respectively, were awarded under the plan. Prior
to 1991, 259,350 shares were awarded under the plan. Related
compensation expense of $735,000, $673,000 and $548,000 was
recognized in fiscal 1993, 1992 and 1991, respectively. At
September 30, 1993, 493,800 shares were currently available for
award.
7. Employee retirement and stock ownership plans
At September 30, 1993, the Company had three defined benefit
retirement plans. One covers the Kentucky employees, one covers
the Greeley Gas Division employees, and the other covers all
other employees of the Company. The plans provide essentially
the same benefits to all employees. Benefits are based on years
of service and the employee's compensation during the highest
paid five consecutive calendar years within the last 10 years of
employment. The Company's funding policy is to contribute annu-
ally an amount in accordance with the requirements of the Em-
ployee Retirement Income Security Act of 1974. Contributions are
intended to provide not only for benefits attributed to service
to date but also for those expected to be earned in the future.
28<PAGE>
The following table sets forth the combined funded status of
Atmos' defined benefit retirement plans at June 30, 1993 and 1992
and amounts recognized in the Company's balance sheets at Septem-
ber 30, 1993 and 1992 for the plans covering Atmos' employees
except for employees of the Greeley Gas Division:
1993 1992
--------- --------
(In thousands)
Actuarial present value of benefit obligations
Accumulated benefit obligation,
including vested benefits of $86,141
and $73,726 in 1993 and 1992,
respectively $ (87,006) $(74,473)
========= ========
Projected benefit obligation $(100,214) $(86,495)
Plan assets at fair value 114,772 104,037
--------- --------
Plan assets in excess of projected
benefit obligation 14,558 17,542
Unrecognized net asset being
recognized over 13 years (851) (1,069)
Unrecognized prior service cost 482 572
Unrecognized net gain (2,032) (4,181)
--------- --------
Prepaid pension cost $ 12,157 $ 12,864
========= ========
Net periodic pension cost (credit) for fiscal 1993, 1992 and
1991 included the following components:
1993 1992 1991
-------- -------- --------
(In thousands)
Service cost - benefits earned
during the year $ 2,182 $ 2,117 $ 2,186
Interest cost on projected benefit
obligation 7,258 6,783 6,464
Actual return on plan assets (15,049) (12,534) (4,788)
Net amortization and deferral 6,316 3,981 (3,711)
-------- -------- --------
Net periodic pension cost $ 707 $ 347 $ 151
======== ======== ========
The weighted-average discount rates used in determining the
actuarial present value of the projected benefit obligation were
7.75% and 8.50% at June 30, 1993 and 1992, respectively. The
rate of increase in future compensation levels reflected in such
determination was 5.0% for the years ended September 30, 1993 and
1992. The expected long-term rate of return on assets was 8.5%,
9.0% and 9.0% for the years ended September 30, 1993, 1992 and
1991, respectively. The plan assets consist primarily of invest-
ments in common stocks, interest bearing securities and interests
29<PAGE>
in commingled pension trust funds. Prepaid pension cost is
included in deferred charges and other assets.
The following table sets forth the Greeley Gas Division
plan's funded status at September 30, 1993 and December 31, 1992.
1993 1992
--------- --------
(In thousands)
Actuarial present value of benefit obligations
Accumulated benefit obligation,
including vested benefits of $9,959
and $8,730 in 1993 and 1992,
respectively $ (10,088) $ (8,831)
Additional amounts related to projected pay
increases (3,271) (3,453)
--------- --------
Projected benefit obligation $ (13,359) $(12,284)
Plan assets at fair value 14,204 13,461
--------- --------
Plan assets in excess of projected
benefit obligation 845 1,177
Unrecognized net asset being
recognized over 15 years (2,390) (2,607)
Unrecognized net loss from past
experience different from that
assumed 2,677 2,460
--------- --------
Prepaid pension cost $ 1,132 $ 1,030
========= ========
Net periodic pension cost (credit) for fiscal 1993, 1992 and
1991 included the following components:
1993 1992 1991
-------- -------- --------
(In thousands)
Service cost $ 374 $ 385 $ 384
Interest cost on projected benefit
obligation 954 952 884
Actual return on plan assets (1,180) (1,146) (1,052)
Net amortization and deferral (257) (218) (172)
-------- -------- --------
Net pension expense (credit) $ (109) $ (27) $ 44
======== ======== ========
Accumulated plan benefits were computed using the Projected
Unit Credit funding method. The discount rate and rate of in-
crease in future compensation levels used in determining the
actuarial present value of the projected benefit obligations were
7.75% and 6.25%, respectively, in 1993 and 8.5% and 7%, respec-
tively, in 1992. The expected long-term rate of return on plan
30 <PAGE>
assets was 9% in 1993 and 1992. Plan assets consist primarily of
corporate bonds, equity securities, mutual funds, partnership
interests, and other miscellaneous investments.
Effective October 1, 1987, the Company adopted a nonquali-
fied Supplemental Executive Benefits Plan ("Supplemental Plan")
which provides additional pension benefits to the executive
officers and certain other employees of the Company. Expense
recognized in connection with the Supplemental Plan during fiscal
1993, 1992 and 1991 was $1,492,000, $872,000 and $678,000, re-
spectively.
The Company sponsors an Employee Stock Ownership Plan
("ESOP"). Full time employees who have completed one year of
service, as defined in the plan, are eligible to participate.
Each participant enters into a salary reduction agreement with
the Company pursuant to which the participant's salary is reduced
by an amount not less than 2% nor more than 10%. Taxes on the
amount by which the participant's salary is reduced are deferred
pursuant to Section 401(k) of the Internal Revenue Code. The
amount of the salary reduction is contributed by the Company to
the ESOP for the account of the participant. The Company may
make a matching contribution for the account of the participant
in an amount determined each year by the Board of Directors,
which amount must be at least equal to 25% of all or a portion of
the participant's salary reduction. For the 1993 plan year, the
Board of Directors elected to match 100% of each participant's
salary reduction contribution up to 4% of the participant's
salary. Matching contributions to the ESOP amounted to
$1,413,000, $1,324,000, and $1,267,000 for fiscal 1993, 1992 and
1991, respectively. The Directors may also approve discretionary
contributions, subject to the provisions of the Internal Revenue
Code of 1986 and applicable regulations of the Internal Revenue
Service. The Company recorded a charge of $1,000,000 for a
discretionary contribution in the year ended September 30, 1993.
Company contributions to the plan are expensed as incurred.
Effective January 1, 1988, the Greeley Gas Division adopted
a 401(k) plan that covers substantially all The Greeley Gas
Division employees. Employee contributions are limited to 6% of
base compensation. The Company matches 50% of employee contribu-
tions. Total employer contributions to the 401(k) plan were
$230,000, $288,000, and $262,000 for the periods ended September
30, 1993, 1992, and 1991, respectively.
In addition to providing pension benefits, the Company
provides certain other postretirement benefits for retired em-
ployees, the major benefit being health care insurance. To be
eligible for these benefits, an employee must retire under the
terms of the Company's retirement plans. The cost of other
postretirement benefits is recognized by expensing claims and
annual insurance premiums as incurred. In fiscal 1993, 1992 and
1991, these costs totaled $1,453,000, $1,626,000 and $1,361,000,
respectively.
31<PAGE>
At September 30, 1993, the Company had not adopted Statement
of Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions" ("SFAS No. 106")
which was released in December 1990. SFAS No. 106 focuses prin-
cipally on postretirement health care benefits and will signifi-
cantly change the current practice of accounting for postretire-
ment benefits on a pay-as-you-go basis by requiring accrual of
the expected cost of those benefits over the years of an em-
ployee's active service to the Company. Two options are provided
for adopting SFAS No. 106. An employer can choose to immediately
recognize its obligation as the effect of an accounting change,
subject to certain limitations. Alternatively, an employer can
choose to recognize its obligation in the statement of financial
position and statement of income on a delayed basis over the plan
participants' future service periods, with disclosure of the
unrecognized amount.
As of September 30, 1993, the Company is allowed to recover
other postretirement benefit costs through its regulated rates on
a pay-as-you-go basis. The Company will adopt SFAS No. 106, as
required, in the first quarter of its 1994 fiscal year under the
delayed recognition method. The transition obligation of
$32,960,000 will be amortized over 20 years. Estimated net
postretirement benefit cost for fiscal 1994 is $5,845,000. None
of the obligation is currently funded.
In its September 1992 rate order to the Trans Louisiana Gas
Company ("Trans La Division"), the Louisiana Public Service
Commission ("Louisiana Commission") directed the Trans La Divi-
sion to remain on a pay-as-you-go basis for ratemaking purposes
and to defer the difference between the cost to be accrued under
SFAS No. 106 and the pay-as-you-go cost as a regulatory asset.
The deferred cost will be recognized for rate recovery when it is
actually paid. In May 1993, the Louisiana Commission issued an
order for all utilities under its jurisdiction to continue to use
the pay-as-you-go accounting method for rate treatment of SFAS
No. 106 costs. Utilities may apply to the Louisiana Commission
for authority to recognize a regulatory asset, to be amortized on
a pay-as-you-go basis, to bridge the gap between ratemaking and
accounting. The Louisiana Commission retains the flexibility to
examine individual companies' accounting for SFAS No. 106 costs
to determine if special exceptions to this order are warranted.
In June 1992, the Kentucky Public Service Commission ("Ken-
tucky Commission") declined a request by a group of utilities to
grant a blanket commitment for the future recovery of SFAS No.
106 costs in excess of pay-as-you-go costs for all utilities.
The Kentucky Commission's order stated that each utility could
file an individual application to seek recovery of such costs.
At a rehearing held in December 1992, the Kentucky Commission
affirmed its initial order.
In May 1993, the Company filed rate requests which included
SFAS No. 106 costs in Fritch and Sanford, Texas and for the
surrounding environs. The rates for the environs are subject to
32<PAGE>
the jurisdiction of the Railroad Commission of Texas ("Railroad
Commission"). In its order of August 30, 1993, the Railroad
Commission approved recovery of SFAS No. 106 cost and internal
funding.
In November 1993, the Kansas Corporation Commission ("Kansas
Commission") issued an order to the Greeley Gas Division allowing
recovery of SFAS No. 106 costs in its Kansas service area, effec-
tive December 1, 1993.
At September 30, 1993, the Greeley Gas Division had a rate
case which included a request for recovery of SFAS No. 106 costs
pending before the Colorado Public Utility Commission.
The Company will seek rate recovery of accrual based SFAS
No. 106 expenses in all of its ratemaking jurisdictions. The
portion of this additional expense in excess of the pay-as-you-go
amount that will immediately or ultimately be allowed in rates
cannot presently be determined. In addition, the degree of
regulatory assurance of future recovery that may be required to
recognize a regulatory asset cannot be determined at this time.
The ultimate impact of the adoption of SFAS No. 106 on the Com-
pany's financial position and results of operations will not be
known with certainty until the standard is adopted and the regu-
latory treatment that will be allowed in each of the Company's
ratemaking jurisdictions is determined.
The Company also provides postemployment benefits, primarily
workers' compensation and long-term disability insurance, to
former or inactive employees after employment but before retire-
ment. The Financial Accounting Standards Board has issued State-
ment of Financial Accounting Standards No. 112, "Employers'
Accounting for Postemployment Benefits" ("SFAS No. 112"), which
applies to such benefits and will be effective for the Company's
1995 fiscal year. Under SFAS No. 112, employers are required to
recognize the obligation to provide postemployment benefits if
certain conditions are met. Based on a preliminary actuarial
study, the Company currently estimates that the cumulative effect
of implementation of SFAS No. 112 and the increase in future
annual costs to be minimal. The reduction in future earnings
that would result from this accrual would be offset to the extent
that it is approved to be recovered in rates. The impact of
adoption of SFAS No. 112 on the Company's ongoing earnings is
expected to be minimal.
33
8. Supplementary information
Taxes, other than income taxes for fiscal 1993, 1992 and
1991 consisted of the following:
1993 1992 1991
------- ------- -------
(In thousands)
Gross receipts $ 7,312 $ 7,393 $ 6,960
Ad valorem 4,992 4,618 4,622
Payroll 3,353 3,322 3,243
Other 1,149 1,065 469
------- ------- -------
$16,806 $16,398 $15,294
======= ======= =======
9. Contingencies
On March 15, 1991, suit was filed in the 15th Judicial Dis-
trict Court of Lafayette Parish, Louisiana, by the "Lafayette
Daily Advertiser" and others against the Trans La Division, Trans
Louisiana Industrial Gas Company, Inc. ("TLIG"), a wholly owned
subsidiary of the Company, and Louisiana Intrastate Gas Corpora-
tion and certain of its affiliates ("LIG"). LIG is the Company's
primary supplier of natural gas in Louisiana and is not otherwise
affiliated with the Company.
The plaintiffs purported to represent a class consisting of
all residential and commercial gas customers in the Trans La
Division's service area. Among other things, the lawsuit alleged
that the defendants violated antitrust laws of the state of
Louisiana by manipulating the cost-of-gas component of the Trans
La Division's gas rate to the purported customer class, thereby
causing such purported class members to pay a higher rate. The
plaintiffs made no specific allegation of an amount of damages.
The defendants brought an appeal to the Louisiana Supreme
Court of rulings by the trial court and the Third Circuit Court
of Appeal which denied defendants' exceptions to the jurisdiction
of the trial court. It was the position of the defendants that
the plaintiffs' claims amount to complaints about the level of
gas rates and should be within the exclusive jurisdiction of the
Louisiana Commission.
On January 19, 1993, the Louisiana Supreme Court issued a
decision reversing in part the lower courts' rulings, dismissing
all of plaintiffs' claims against the defendants which seek
damages due to alleged overcharges and further ruling that all
such claims are within the exclusive jurisdiction of the Louisi-
ana Commission. Any claims which seek damages other than over-
charges were remanded to the trial court but were stayed pending
the completion of the Louisiana Commission proceeding referred to
below.
The Louisiana Commission has instituted a docketed proceeding
for the purpose of investigating the costs included in the Trans
La Division's purchased gas adjustment component of its rates.
Both the Trans La Division and LIG are parties to the proceeding.
Discovery has commenced in this proceeding and a procedural
schedule has been established. The Company believes the allega-
tions as they relate to the Company, whether brought in court or
at the Louisiana Commission, are without merit, and that the
chances of a material adverse outcome are remote. The Company
will continue to vigorously protect its interest in this matter.
34 <PAGE>
From time to time, claims are made and lawsuits are filed
against the Company arising out of the ordinary business of the
Company. In the opinion of the Company's management, liabili-
ties, if any, arising from these actions are either covered by
insurance, adequately reserved for by the Company or would not
have a material adverse effect on the financial condition of the
Company.
10. Statement of cash flows
Supplemental disclosures of cash flow information for fiscal
1993, 1992 and 1991 are presented below:
1993 1992 1991
------- ------- -------
(In thousands)
Cash paid for
Interest $13,436 $14,496 $13,310
Income taxes 8,190 3,754 4,422
11. Leases
The Company has entered into noncancelable leases involving
office space and warehouse space. The remaining lease terms
range from one to 20 years and generally provide for the payment
of taxes, insurance and maintenance by the lessee. At September
30, 1993, a substantial number of the leases at the Greeley Gas
Division were with shareholders. Net property, plant and equip-
ment included amounts for capital leases of $6,029,000 and
$6,374,000 at September 30, 1993 and 1992, respectively.
35<PAGE>
The related future minimum lease payments at September 30, 1993
were as follows:
Capital Operating
leases leases
-------- --------
(In thousands)
1994 $ 1,404 $ 4,702
1995 1,403 4,800
1996 1,404 4,539
1997 1,370 3,522
1998 1,315 2,661
Thereafter 9,287 20,338
------- -------
Total minimum lease payments 16,183 40,562
Less amount representing
contingent payments from
increases in the Consumer
Price Index (1,087) (20)
------- -------
Net minimum lease payments 15,096 $40,542
=======
Less amount representing interest (8,573)
-------
Present value of net minimum
lease payments $ 6,523
=======
Consolidated rent expense amounted to $5,277,000, $5,395,000
and $4,291,000 for fiscal 1993, 1992 and 1991, respectively.
Rents are expensed and recovered in rates on a pay-as-you-go
basis.
SUPPLEMENTARY DATA
Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data are presented
below. The sum of net income per share by quarter may not equal
the net income per share for the year due to variations in the
weighted average shares outstanding used in computing such
amounts.
36<PAGE>
<TABLE>
<CAPTION>
Quarter ended
-------------------------------------------------------------------------------
December 31, March 31, June 30, September 30,
----------------- ----------------- ----------------- -----------------
1992 1991 1993 1992 1993 1992 1993 1992
-------- -------- -------- -------- -------- -------- -------- --------
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $130,700 $125,058 $166,238 $140,327 $ 91,219 $ 70,780 $ 71,484 $ 67,188
Gross profit 42,638 42,947 58,606 49,644 34,463 28,485 27,402 25,186
Operating income 9,730 9,088 17,120 13,250 3,970 1,256 (543) (25)
Net income (loss) 6,764 5,686 13,760 10,464 830 (1,627) (3,810) (3,525)
Net income (loss) per
share .48 .42 .97 .76 .06 (.12) (.26) (.25)
</TABLE>
37<PAGE>
<TABLE>
ATMOS ENERGY CORPORATION
SCHEDULE V
PROPERTY, PLANT AND EQUIPMENT
<CAPTION>
Balance at Balance
beginning Additions Retirements at end
of year at cost or sales Other of year
--------- ------- --------- ----- ---------
(In thousands)
<S> <C> <C> <C> <C> <C>
Year ended September 30, 1993:
Utility plant $458,548 $41,824 $ 4,219 $ - $496,153
Construction in progress 4,065 1,319 25 - 5,359
-------- ------- -------- ----- --------
$462,613 $43,143 $ 4,244 $ - $501,512
======== ======= ======== ===== ========
Year ended September 30, 1992:
Utility plant $421,048 $41,613 $ 4,113 $ - $458,548
Construction in progress 3,519 556 10 - 4,065
-------- ------- -------- ----- --------
$424,567 $42,169 $ 4,123 $ - $462,613
======== ======= ======== ===== ========
Year ended September 30, 1991:
Utility plant $393,753 $37,519 $ 10,224 $ - $421,048
Construction in progress 3,461 111 53 - 3,519
-------- ------- -------- ----- --------
$397,214 $37,630 $ 10,277 $ - $424,567
======== ======= ======== ===== ========
</TABLE>
Depreciation is provided at various rates on a straight-line
basis over the estimated useful lives of the assets. Such rates
range from 2% to 33% per year with the average rate currently
being approximately 3.7% per year. <PAGE>
38
39<PAGE>
<TABLE>
ATMOS ENERGY CORPORATION
SCHEDULE VI
ACCUMULATED DEPRECIATION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
<CAPTION>
Additions Deductions -
Balance at charged to to retirements, Balance
beginning costs and renewals and at end
of year expenses replacements Other of year
---------- --------- ------------- ------- --------
(In thousands)
<S> <C> <C> <C> <C> <C>
Year ended September 30, 1993:
Utility plant $185,689 $19,857 $ 3,309 $ - $202,237
Year ended September 30, 1992:
Utility plant $165,380 $21,803 $ 1,494 $ - $185,689
Year ended September 30, 1991:
Utility plant $152,023 $20,235 $ 6,878 $ - $165,380
</TABLE>
40<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, hereunto duly authorized.
ATMOS ENERGY CORPORATION
(Registrant)
Date: July 21, 1994 By /s/ JAMES F. PURSER
------------------------
James F. Purser
Executive Vice President and
Chief Financial Officer
41<PAGE>
EXHIBITS INDEX
Exhibit Sequentially Numbered
Number Description Page or Incorporation by
Reference to
23 Consent of independent auditor
42<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITOR
We consent to the incorporation by reference in the Registration
Statements (Form S-8 No. 33-68852, Form S-8 No. 2-89113, Form S-3
No. 33-58220, and Form S-3 No. 33-70212) of Atmos Energy
Corporation and in the related Prospectuses of our report dated
November 10, 1993, except for Notes 2 and 5, as to which the date
is February 9, 1994, with respect to the consolidated financial
statements and schedules of Atmos Energy Corporation included in
this Current Report (Form 8-K).
ERNST & YOUNG
Dallas, Texas
July 21, 1994
1<PAGE>
