<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to ____________
Commission File Number 1-10042
ATMOS ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS AND VIRGINIA 75-1743247
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas 75240
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ----------------------
Common stock, No Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
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 X No
--- ---
"continued"
<PAGE>
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was $660,086,573 as of November 24, 1999. On November 24,
1999 the registrant had 31,316,186 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Annual Report to Shareholders for the
year ended September 30, 1999 are incorporated by reference into Parts I, II and
IV of this report.
Portions of the registrant's Definitive Proxy Statement to be filed
for the Annual Meeting of Shareholders on February 9, 2000 are incorporated by
reference into Part III of this report.
<PAGE>
ATMOS ENERGY CORPORATION
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 1999
TABLE OF CONTENTS
Page no.
Cautionary statement regarding forward-looking statements 5
PART I
Item 1. Business 6
Acquisitions and Mergers 8
Operating Statistics 9
Utility Energy Services and Propane Data 14
Gas Sales 15
Gas Supply 16
Regulation and Rates 18
Competition 22
Employees 23
Item 2. Properties 23
Item 3. Legal Proceedings 24
Item 4. Submission of Matters to a
Vote of Security Holders 24
Executive Officers of the Registrant 25
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters 26
Item 6. Selected Financial Data 26
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 26
Item 7A. Quantitative and Qualitative Disclosures
about Market Risk 26
3
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Page no.
Item 8. Financial Statements and Supplementary Data 27
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 27
PART III
Item 10. Directors and Executive Officers
of the Registrant 28
Item 11. Executive Compensation 28
Item 12. Security Ownership of Certain Beneficial
Owners and Management 28
Item 13. Certain Relationships and Related Transactions 28
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K 29
4
<PAGE>
Cautionary Statement under the Private Securities Litigation Reform Act of 1995
The matters discussed or incorporated by reference in this Annual Report on
Form 10-K may contain "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934. All statements other than statements
of historical facts included in this Report regarding the Company's financial
position, business strategy and plans and objectives of management of the
Company for future operations, are forward-looking statements made in good faith
by the Company and are intended to qualify for the safe harbor from liability
established by the Private Securities Litigation Reform Act of 1995. When used
in this Report or in any of the Company's other documents or oral presentations,
the words "anticipate," "expect," "estimate," "plans," "believes," "objective,"
"forecast," "goal" or other similar words are intended to identify forward-
looking statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those
expressed or implied in the statements relating to the Company's operations,
markets, services, rates, recovery of costs, availability of gas supply, and
other factors. These risks and uncertainties include, but are not limited to,
national, regional, and local economic and competitive conditions, regulatory
and business trends and decisions, technological developments, Year 2000 issues,
inflation rates, weather conditions, and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the Company.
Accordingly, while the Company believes that the expectations reflected in
the forward-looking statements are reasonable, there can be no assurance that
such expectations will be realized or will approximate actual results.
5
<PAGE>
PART I
ITEM 1. BUSINESS
Atmos Energy Corporation (the "Company") was organized under the laws of
the State of Texas in 1983 as a subsidiary of Pioneer Corporation ("Pioneer")
for the purposes of owning and operating Pioneer's natural gas distribution
business in Texas. Immediately following the transfer of such business, which
had been operated by Pioneer and its predecessors since 1906, Pioneer
distributed the outstanding stock of the Company, then known as Energas Company,
to Pioneer shareholders. In September 1988, the Company changed its name from
Energas Company to Atmos Energy Corporation. As a result of its merger with
United Cities Gas Company in July 1997, the Company became incorporated in the
Commonwealth of Virginia as well as the State of Texas.
The Company distributes and sells natural gas and propane to approximately
1,078,000 residential, commercial, industrial, agricultural, and other
customers. The Company distributes and sells natural gas through approximately
1,038,000 meters in 802 cities, towns, and communities in service areas located
in Texas, Louisiana, Kentucky, Colorado, Kansas, Illinois, Tennessee, Iowa,
Virginia, Georgia, South Carolina and Missouri. The Company also transports gas
for others through parts of its distribution system. It also distributes propane
to approximately 40,000 customers in Kentucky, North Carolina, Virginia, and
Tennessee.
The Company's Texas distribution system is operated through its Energas
Company division (the "Energas Division") and covers an area having a population
of approximately 950,000 people. The economy of the area is based primarily on
oil and gas production and agriculture. The principal cities served by the
Energas Division include Amarillo, Lubbock, Midland, and Odessa. At September
30, 1999, the Company had approximately 316,000 regulated and non-regulated
meters in service in Texas.
The Company's Louisiana distribution system is operated through its Trans
Louisiana Gas Company division (the "Trans La Division") and covers an area
having a population of approximately 250,000 people. The economy of the area is
based primarily on oil and gas production, agriculture, and food processing. The
principal cities served by the Trans La Division are Lafayette, Pineville, and
Natchitoches. At September 30, 1999, the Company had approximately 81,000 meters
in service in Louisiana.
The Company's Kentucky distribution system is operated through its Western
Kentucky Gas Company division (the "Western Kentucky Division") and covers an
area having a population of approximately 680,000 people. The economy of the
area is based primarily on industry and agriculture. The principal cities served
by the Western Kentucky Division include Bowling Green, Owensboro, and
6
<PAGE>
Paducah. At September 30, 1999, the Company had approximately 180,000 meters in
service in Kentucky.
The Company's distribution systems in Colorado and parts of Kansas and
Missouri are operated through its Greeley Gas Company division (the "Greeley
Division") and covers an area having a combined population of approximately
530,000 people. The economies of the areas served are based on oil and gas
production, agriculture and resort business. The principal cities and counties
served by the Greeley Division include Greeley, Durango and Lamar, Colorado;
Bonner Springs, Herington and Ulysses, Kansas; and Wyandotte and Johnson
Counties in Kansas. At September 30, 1999 the Greeley Division had approximately
202,000 meters in service.
The Company operates natural gas distribution systems in Georgia, Illinois,
Iowa, South Carolina, Tennessee, Virginia and Missouri through its United Cities
Gas Company division (the "United Cities Division") and covers an area having a
combined population of approximately 6.4 million people. The economies of the
areas served include customers engaged in the manufacture of asphalt,
automobiles, auto parts, chemicals, electronics, food products, metals, textiles
and wire, among others. The division also serves several colleges and a major
army base. The principal cities served by the United Cities Division include
Franklin and Murfreesboro, Tennessee; Hannibal, Missouri; and Gainesville and
Columbus, Georgia. At September 30, 1999, the United Cities Division had
approximately 259,000 meters in service.
The Company also operates certain non-regulated businesses through various
wholly-owned subsidiaries. One subsidiary, Atmos Storage, Inc. ("Storage"),
provides natural gas storage services. It owns natural gas storage fields in
Kentucky and Kansas to supplement natural gas used by customers in Kansas,
Tennessee, and other states.
Another subsidiary, Atmos Energy Marketing, LLC, owns a 45% interest in
Woodward Marketing, LLC ("WMLLC"), a Delaware limited liability company that
provides natural gas services. WMLLC provides gas marketing and energy
management services to industrial customers, municipalities and local
distribution companies, including the Trans La, Western Kentucky and United
Cities Divisions.
In addition, Atmos Energy Services, Inc. markets gas to industrial and
irrigation customers primarily in West Texas through Enermart Energy Services
Trust ("Enermart") and to industrial customers in Louisiana, and is developing
plans for marketing various non-regulated services and products.
United Cities Propane Gas, Inc. ("Propane") is engaged primarily in the
retail distribution of propane ("LP") gas, and on a much smaller scale, the
wholesale supply of LP gas. It exited
7
<PAGE>
the direct merchandising and repair of propane gas appliances in 1999. Propane
currently has operation and storage centers and storefront offices located in
Tennessee, Kentucky, and North Carolina, with a total company storage capacity
of approximately 2.5 million gallons. As of September 30, 1999, Propane served
approximately 40,000 customers in the states listed above as well as Virginia.
During the three-year period ended September 30, 1999, the propane operations
added approximately 10,900 customers through acquisitions of six propane
distribution companies and a propane transport company.
Finally, Atmos Leasing Inc. and Atmos Energy Marketing, LLC, leases real
estate and vehicles to the United Cities Division and leases appliances to
residential customers.
The natural gas distribution business is subject to a number of factors,
many of which affect the Company from time to time. These include (i) the
ongoing need to obtain adequate and timely rate relief from regulatory
authorities to recover costs of service and earn a fair return on invested
capital; (ii) inherent seasonality of the business; (iii) competition with
alternate fuels; (iv) competition with other gas sources for industrial
customers, including the ability of some customers to bypass the Company's
facilities, which could result in loss of revenues and reduction in the
Company's net income; and (v) possible volatility in the supply and price of
natural gas and propane. The propane distribution business is also subject to
seasonality and competition with alternate fuels and other suppliers.
ACQUISITIONS AND MERGERS
Since its organization in 1983, the Company has sought to expand its
customer base and to diversify the weather patterns, local economic conditions,
and regulatory environments to which its operations are subject. As part of
this strategy, the Company acquired Trans Louisiana Gas Company, Inc. ("TLG") in
January 1986, Western Kentucky Gas Utility Corporation ("WKG") in December 1987,
Greeley Gas Company ("GGC") in December 1993, Oceana Heights Gas Company of
Thibodaux, Louisiana in November 1995 and United Cities Gas Company ("UCGC") in
July 1997. Subsequent to September 30, 1999, the Company entered into a
definitive agreement with Southwestern Energy Company ("Southwestern") on
October 15, 1999 to acquire the Missouri natural gas distribution assets of
Associated Natural Gas, a division of Arkansas Western Gas, which is a wholly-
owned subsidiary of Southwestern. Under the terms of the agreement, the Company
will purchase the Missouri gas system for approximately $32.0 million in cash
plus working capital adjustments. This transaction, which will add
approximately 48,000 customers, is expected to be completed by mid-year 2000,
subject to approvals by the Missouri Public Service Commission and the Federal
Energy Regulatory Commission.
8
<PAGE>
The Company continues to consider and pursue, where appropriate, additional
acquisitions of natural gas distribution properties and other business
opportunities. For further information regarding the UCGC merger, see Note 2 of
notes to consolidated financial statements in the Company's Annual Report to
Shareholders.
OPERATING STATISTICS
The table on the following page reflects the operating statistics of Atmos
including the United Cities Division for fiscal 1999 and 1998 and the restated
operating statistics for 1997, 1996 and 1995 on a pooled basis with UCGC. It is
followed by two tables of utility sales and operating statistics by business
unit for 1999 and 1998, respectively. Certain prior year amounts have been
reclassified to conform with the current year presentation.
9
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED OPERATING STATISTICS
<TABLE>
<CAPTION>
Year ended September 30,
-------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- ---------
<S> <C> <C> <C> <C> <C>
METERS IN SERVICE, end of year
Residential 919,012 889,074 870,747 860,229 834,376
Commercial 98,268 94,302 92,703 91,960 90,093
Industrial 14,329 16,322 17,217 19,403 19,762
Public authority and other 6,386 4,834 4,781 4,716 4,982
----------- ----------- ----------- ----------- ---------
Total meters 1,037,995 1,004,532 985,448 976,308 949,213
Propane customers 39,539 37,400 29,097 26,108 23,359
----------- ----------- ----------- ----------- ---------
Total 1,077,534 1,041,932 1,014,545 1,002,416 972,572
=========== =========== =========== =========== =========
HEATING DEGREE DAYS (2)
Actual (weighted average) 3,374 3,799 3,909 4,043 3,706
Percent of normal 85% 95% 98% 101% 93%
SALES VOLUMES - MMcf (3)
Residential 67,128 73,472 75,215 77,001 69,666
Commercial 31,457 36,083 37,382 38,247 34,921
Industrial(including agricultural) 35,741 44,881 46,416 57,863 57,290
Public authority and other 5,793 4,937 5,195 5,182 4,779
----------- ----------- ----------- ----------- ---------
Total sales volumes 140,119 159,373 164,208 178,293 166,656
Transportation volumes - MMcf (3) 55,468 56,224 48,800 44,146 47,647
----------- ----------- ----------- ----------- ---------
TOTAL THROUGHPUT - MMcf (3) 195,587 215,597 213,008 222,439 214,303
=========== =========== =========== =========== =========
PROPANE - Gallons (000's) 22,291 23,412 25,204 33,637 28,854
=========== =========== =========== =========== =========
OPERATING REVENUES (000's)
Gas sales revenues
Residential $ 349,691 $ 410,538 $ 452,864 $ 409,039 $ 337,768
Commercial 144,836 184,046 193,302 186,032 150,949
Industrial(including agricultural) 117,382 161,382 168,386 187,693 171,591
Public authority and other 22,330 20,504 23,898 21,738 18,185
----------- ----------- ----------- ----------- ---------
Total gas sales revenues 634,239 776,470 838,450 804,502 678,493
Transportation revenues 23,101 23,971 19,885 18,872 19,813
Other gas revenues 4,500 8,121 6,385 13,751 9,374
----------- ----------- ----------- ----------- ---------
Total gas revenues 661,840 808,562 864,720 837,125 707,680
Propane revenues 22,944 29,091 33,194 38,372 24,651
Other revenues 5,412 10,555 8,921 11,194 17,224
----------- ----------- ----------- ----------- ---------
Total operating revenues $ 690,196 $ 848,208 $ 906,835 $ 886,691 $ 749,555
=========== =========== =========== =========== =========
AVERAGE SALES PRICE/Mcf $4.53 $4.87 $5.11 $4.51 $4.07
AVERAGE COST OF GAS/Mcf SOLD 2.79 3.24 3.51 3.15 2.70
AVERAGE TRANSPORTATION REVENUES/Mcf .42 .43 .41 .43 .42
</TABLE>
See footnotes on page 13.
10
<PAGE>
UTILITY SALES AND STATISTICAL DATA BY BUSINESS UNIT - 1999 (1)
<TABLE>
<CAPTION>
Year ended September 30, 1999
------------------------------------------------------------------
Western United Total
Energas Trans La Kentucky Greeley Cities Utility
--------- --------- --------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
METERS IN SERVICE,
at end of year
Residential 274,452 74,890 159,449 181,859 228,362 919,012
Commercial 26,300 5,567 18,371 17,736 30,294 98,268
Industrial (incl.
agricultural) 13,014 128 238 339 610 14,329
Public authority
and other 2,230 893 1,559 1,704 - 6,386
-------- ------- -------- -------- -------- ----------
Total 315,996 81,478 179,617 201,638 259,266 1,037,995
======== ======= ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual 3,083 1,265 3,472 4,992 3,168 3,374
Normal 3,531 1,771 4,333 5,696 3,784 3,990
Percent of normal 87% 71% 80% 88% 84% 85%
SALES VOLUMES-MMcf(3)
Residential 20,871 3,111 11,822 16,748 14,576 67,128
Commercial 6,825 1,334 5,122 6,642 11,534 31,457
Industrial (incl.
agricultural) 1,514 - 2,973 1,462 14,952 20,901
Public authority
and other 2,234 769 1,371 1,419 - 5,793
-------- ------- -------- -------- -------- ----------
Total 31,444 5,214 21,288 26,271 41,062 125,279
TRANSPORTATION
VOLUMES-MMcf(3) 4,637 696 25,814 10,021 14,300 55,468
-------- ------- -------- -------- -------- ----------
TOTAL THROUGHPUT-MMcf(3) 36,081 5,910 47,102 36,292 55,362 180,747
======== ======= ======== ======== ======== ==========
OTHER STATISTICS
Operating
revenues (000's) $123,656 $36,644 $100,165 $132,093 $224,755 $ 617,313
Miles of pipe 13,244 2,276 3,668 5,676 5,806 30,670
Employees(4) 372 128 258 286 427 1,471
Communities served 92 41 163 123 383 802
</TABLE>
See footnotes on page 13.
11
<PAGE>
UTILITY SALES AND STATISTICAL DATA BY BUSINESS UNIT - 1998 (1)
<TABLE>
<CAPTION>
Year ended September 30, 1998
------------------------------------------------------------------
Western United Total
Energas Trans La Kentucky Greeley Cities Utility
--------- --------- --------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
METERS IN SERVICE,
at end of year
Residential 272,190 74,522 156,107 176,316 209,939 889,074
Commercial 25,982 5,526 18,000 19,367 25,427 94,302
Industrial (incl.
agricultural) 14,753 123 442 409 595 16,322
Public authority
and other 2,278 977 1,579 - - 4,834
-------- ------- -------- -------- -------- ----------
Total 315,203 81,148 176,128 196,092 235,961 1,004,532
======== ======= ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual 3,669 1,725 3,771 5,322 3,544 3,799
Normal 3,531 1,771 4,333 5,696 3,784 3,989
Percent of normal 104% 97% 87% 93% 94% 95%
SALES VOLUMES-MMcf(3)
Residential 23,594 3,670 12,413 17,602 16,193 73,472
Commercial 7,754 1,433 5,530 9,321 12,045 36,083
Industrial (incl.
agricultural) 2,076 - 3,415 1,783 14,982 22,256
Public authority
and other 2,559 917 1,461 - - 4,937
-------- ------- -------- -------- -------- ----------
Total 35,983 6,020 22,819 28,706 43,220 136,748
TRANSPORTATION
VOLUMES-MMcf(3) 5,526 949 25,813 10,244 13,692 56,224
-------- ------- -------- -------- -------- ----------
TOTAL THROUGHPUT-MMcf(3) 41,509 6,969 48,632 38,950 56,912 192,972
======== ======= ======== ======== ======== ==========
OTHER STATISTICS
Operating
revenues (000's) $156,170 $36,326 $123,588 $148,331 $274,030 $ 738,445
Miles of pipe 13,217 2,248 3,647 5,322 5,674 30,108
Employees(4) 401 134 267 193 621 1,616
Communities served 92 41 163 123 383 802
</TABLE>
See footnotes on page 13.
12
<PAGE>
Notes to preceding tables:
- --------------------------
(1) These tables present data for Atmos' five utility business units.
Their operations include the regulated local distribution companies located in
their respective service areas.
(2) A heating degree day is equivalent to each degree that the average of
the high and the low temperatures for a day is below 65 degrees. The greater
the number of heating degree days, the colder the climate. Heating degree days
are used in the natural gas industry to measure the relative coldness of weather
experienced and to compare relative temperatures between one geographic area and
another. Normal degree days are based on 30-year average National Weather
Service data for selected locations.
(3) Volumes are reported as metered in million cubic feet ("MMcf").
(4) The number of employees excludes 427 and 391 Atmos shared services and
customer support center employees and 164 and 186 non-utility employees in 1999
and 1998, respectively.
13
<PAGE>
UTILITY, ENERGY SERVICES AND PROPANE DATA
The following table summarizes certain information regarding the
operation of the utility, energy services and propane segments of the Company
for each of the three years as of and for the period ended September 30, 1999.
Amounts for 1997 have been restated to reflect the pooling of interests with
UCGC on July 31, 1997.
Energy
Utility Services Propane Total
---------- -------- -------- ----------
(In thousands)
1999
Operating revenues (1) $ 617,313 $49,939 $22,944 $ 690,196
Operating income (loss) 49,000 5,782 (543) 54,239
Net income (loss) 10,800 7,813 (869) 17,744
Identifiable assets (1) 1,125,691 71,115 33,731 1,230,537
1998
Operating revenues (1) $ 738,445 $80,672 $29,091 $ 848,208
Operating income 100,665 11,595 619 112,879
Net income (loss) 43,332 11,999 (66) 55,265
Identifiable assets (1) 1,052,225 52,616 36,549 1,141,390
1997
Operating revenues (1) $ 805,252 $68,389 $33,194 $ 906,835
Operating income 61,213 4,991 405 66,609
Net income (loss) 19,739 4,189 (90) 23,838
Identifiable assets (1) 1,002,690 62,511 23,110 1,088,311
(1) Net of intersegment eliminations
The utility segment is comprised of the Company's five regulated utility
divisions: Energas Division, Greeley Division, Trans La Division, United Cities
Division and Western Kentucky Division.
The energy services segment is currently composed of four parts. Atmos
Storage Inc., owns underground storage fields in Kansas and Kentucky and
provides storage services to the United Cities Division and Greeley Division and
other non-regulated customers. Atmos Energy Services, Inc., markets gas to
irrigation and industrial customers in West Texas through Enermart Energy
Services Trust, and to industrial customers in Louisiana and is developing plans
for marketing various non-regulated services and products. Atmos Energy
Marketing, LLC, owns the Company's 45% investment in WMLLC, a gas marketing and
energy management services business. Atmos Leasing, Inc., leases buildings and
vehicles to the United Cities Division and gas appliances to residential
customers.
14
<PAGE>
The propane segment includes United Cities Propane Gas, Inc., which is
primarily engaged in the retail and wholesale distribution of propane gas in
Tennessee, Kentucky, North Carolina and Virginia.
GAS SALES
The Company's natural gas distribution business is seasonal and highly
dependent on weather conditions in the Company's service areas. Gas sales to
residential and commercial customers are greater during the winter months than
during the remainder of the year. The volumes of such sales during the winter
months will vary with the temperatures during such months. The seasonal nature
of the Company's sales to residential and commercial customers is offset
partially by the Company's sales in the spring and summer months to its
agricultural customers in Texas, Colorado and Kansas who utilize natural gas to
operate irrigation equipment. The Company also has weather normalization
adjustments in its rate jurisdictions in Tennessee and Georgia, which serve
approximately 186,000 customers. The Company believes that it has lessened its
sensitivity to weather risk by diversifying its operations into geographic areas
having different weather patterns.
In addition to weather, the Company's revenues are affected by the cost of
natural gas and economic conditions in the areas that the Company serves. Higher
gas costs, which the Company is generally able to pass through to its customers
under purchased gas adjustment clauses, may cause customers to conserve, or, in
the case of industrial customers, to use alternative energy sources.
In recent years, natural gas market conditions have changed. Natural gas
prices to distributors have become more volatile and the number of competing
marketers of natural gas has increased. The Company's gas marketing subsidiaries
purchase gas to address requirements for large volume customers in certain
highly competitive markets.
In certain instances, customers purchase gas directly from others instead
of from the Company and the Company transports such gas through its distribution
systems to the customers' facilities for a fee. Although transportation of
customer-owned gas reduces the Company's operating revenues and corresponding
purchased gas cost, the transportation revenues received by the Company
generally offset the loss to gross profit.
The Company's distribution systems have experienced aggregate peak day
deliveries of approximately 1.5 billion cubic feet ("Bcf") per day. The Company
has the ability to curtail deliveries to certain customers under the terms of
interruptible contracts and applicable state statutes or regulations which
enables it to maintain its deliveries to high priority customers. The Company
has not imposed curtailment in its Energas Division since the Company began
independent operations in 1983 or in its Trans La
15
<PAGE>
Division since the Company acquired TLG in 1986. The Western Kentucky Division
curtailed deliveries to certain interruptible customers during exceptionally
cold periods in December 1989, January 1994 and during the winter of 1996.
Neither the Greeley Division nor its predecessor, GGC, have curtailed deliveries
to its sales customers since prior to 1980. The United Cities Division curtails
interruptible service customers from time to time each year in accordance with
the interruptible contracts and tariffs.
GAS SUPPLY
The Company receives gas deliveries through some 28 pipeline transportation
companies, both interstate and intrastate, to satisfy its firm sales market
requirements. The transportation agreements are firm and many of them have
pipeline no-notice storage service which provide for daily balancing between
system requirements and nominated flowing supplies. These agreements have been
negotiated with the shortest term available to maintain the Company's Right of
First Refusal which provides the right to roll over the term and yet reduce the
risk of stranded demand costs in the event of unbundling its services.
The Western Kentucky Division's gas supply is delivered by the following
pipelines: Williams Pipeline-Texas Gas, Tennessee Gas, Trunkline, Midwestern
Pipeline and ANR, except that a small percentage of the requirements are being
purchased directly from intrastate producers that are connected directly to its
distribution system. During 1998, WKG sought and was granted approval by the
Kentucky Public Service Commission for a Performance-based Rate ("PBR") program.
This three-year supply and asset management program commenced in July 1998.
The United Cities Division is served by 13 interstate pipelines. The
majority of the volumes are transported through East Tennessee Pipeline,
Southern Natural Gas and Williams Pipeline-Central.
Colorado Interstate Gas Company, Williams Pipeline-Central, Public Service
Company of Colorado, and Northwest Pipeline are the principal transporters of
the Greeley Division's requirements. Additionally, the Greeley Division
purchased substantial volumes from producers that are connected directly to its
distribution system.
The Energas Division receives sales and transportation service from various
KN pipeline affiliates. Also, the Energas Division purchases a significant
portion of its supply from Pioneer Natural Resources (formerly Mesa) which is
connected directly to the Company's Amarillo, Texas distribution system.
16
<PAGE>
Louisiana Intrastate Gas Company ("LIG"), Acadian Pipeline, Koch Gateway
and Williams Pipeline-Texas Gas pipelines deliver most of the Trans La
Division's requirements.
The Company also owns and operates numerous natural gas storage facilities
in Kentucky and Kansas which are used to help meet customer requirements during
peak demand periods and to reduce the need to contract for additional pipeline
capacity to meet such peak demand periods. Additionally, the Company operates
various propane plants and a liquified natural gas ("LNG") plant for peak
shaving purposes. The Company also contracts for storage service in underground
storage facilities of many of the interstate pipelines serving it. See "Item 2.
Properties" below for further information regarding the peak shaving facilities.
The United Cities and Western Kentucky Gas Divisions normally injects gas
into pipeline storage systems and company owned storage facilities during the
summer months and withdraws it in the winter months. At the present time, the
underground storage facilities of Storage have a maximum daily output capability
of approximately 15,000 thousand cubic feet ("Mcf").
The United Cities Division has the ability to serve approximately 60% of
its peak day load through the use of company owned storage facilities, storage
contracts with its suppliers and peaking facilities throughout the system. This
ability provides the operational flexibility and security of supply required to
meet the needs of the highly weather sensitive residential and commercial
markets.
During 1999, the Company purchased its gas supply from various producers
and marketers. The suppliers were selected through a bidding process (except for
local production purchases) by sending out a Request for Proposal ("RFP") to
suppliers that have demonstrated that they can provide reliable service. These
suppliers were selected based on their ability to deliver gas supply to our
designated firm pipeline receipt points and the best cost. Major suppliers
during 1999 were Reliant Energy, Sonat Marketing, KN Marketing, Pioneer Natural,
CIG the Merchant, WMLLC, Oneok Gas Marketing, Barrett Resources, Anadarko and
Tenaska Marketing.
17
<PAGE>
REGULATION AND RATES
Regulation
- ----------
Energas Division
In the Energas Division, the governing body of each municipality served by
the Company has original jurisdiction over all utility rates, operations, and
services within its city limits except with respect to sales of natural gas for
vehicle fuel and agricultural use. The Company operates pursuant to non-
exclusive franchises granted by the municipalities it serves, which franchises
are subject to renewal from time to time. The franchises granted to the Company
permit it to conduct natural gas distribution within the municipalities'
incorporated limits. The Railroad Commission of Texas has exclusive appellate
jurisdiction over all rate and regulatory orders and ordinances of the
municipalities and exclusive original jurisdiction over rates and services to
customers not located within the limits of a municipality. In Texas, rates for
large industrial customers are routinely set by contract negotiation between the
Company and its customers pursuant to statutory standards and are filed with and
subject to the governmental authority of the municipalities or the Railroad
Commission, depending on whether the customer is located inside or outside the
limits of a municipality. Historically, the Company's rates for large
industrial customers have been accepted as filed. Agricultural sales in Texas
are not regulated, except that prices for agricultural sales cannot exceed the
prices the Company charges the majority of its commercial or other similar
large-volume users in Texas.
Trans La Division
The Trans La Division is regulated by the Louisiana Public Service
Commission, which regulates utility services, rates, and other matters. In most
of the parishes and incorporated areas in which the Company operates in
Louisiana, it does so pursuant to a non-exclusive franchise granted by the
governing authority of each parish or incorporated area. The franchise gives the
Company the general privilege to operate its gas distribution business in, as
well as the right to install its distribution lines along the roadways of, the
parish or the incorporated area. Direct sales of natural gas to industrial
customers in Louisiana who utilize the gas for fuel or in manufacturing
processes and sales of natural gas for vehicle fuel are exempt from regulation.
Western Kentucky Division
The Western Kentucky Division is regulated by the Kentucky Public Service
Commission, which regulates utility services, rates, issuance of securities, and
other matters. The Company operates in the various incorporated cities served by
it in Kentucky pursuant to non-exclusive franchises granted by such cities. The
franchises
18
<PAGE>
grant to the Company the right to operate its gas distribution business in the
city and to install its distribution lines and related equipment in and along
the city's public rights-of-way. Sales of natural gas for use as vehicle fuel in
Kentucky are not subject to regulation.
Greeley Division
The Greeley Division is regulated by the Colorado Public Utilities
Commission, the Kansas Corporation Commission, and the Missouri Public Service
Commission with respect to accounting, rates and charges, operating matters, and
the issuance of securities. The Company operates in the various incorporated
cities served by it in the states of Colorado, Kansas and Missouri under terms
of non-exclusive franchises granted by the various cities. The franchises grant
to the Company, among other things, the right to install and operate its gas
distribution system within the city limits. Most of the Greeley Division's
wholesale gas suppliers are regulated by various federal and state commissions.
United Cities Division
In each state in which the United Cities Division operates, its rates,
services and operations as a natural gas distribution company is subject to
general regulation by the state public service commission. In addition, the
issuance of securities by the Company is subject to approval by the state
commissions, except in South Carolina and Iowa. Missouri only regulates the
issuance of secured debt. The United Cities Division operates in each community,
where necessary, under a franchise granted by the municipality for a fixed term
of years. To date, it has been able to renew franchises and expects to continue
to do so in the future.
The Company is also subject to regulation by the United States Department
of Transportation with respect to safety requirements in the operation and
maintenance of its gas distribution facilities. The Company's distribution
operations are also subject to various state and federal laws regulating
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 applicable safety and environmental 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.
19
<PAGE>
Rates
- -----
Approximately 89% of the Company's revenues in fiscal 1999 were derived
from sales at rates set by or subject to approval by local or state authorities.
The method of determining regulated rates varies among the twelve states in
which the Company has utility operations. As a general rule, the regulatory
authority reviews the Company's rate request and establishes a rate structure
intended to generate revenue sufficient to cover the Company's costs of doing
business and provide a reasonable return on invested capital.
Substantially all of the sales rates charged by the Company to its
customers fluctuate with the cost of gas purchased by the Company. Rates
established by regulatory authorities are adjusted for increases and decreases
in the Company's purchased gas cost through automatic purchased gas adjustment
mechanisms. Therefore, while the Company's operating revenues may fluctuate,
gross profit (which is defined as operating revenues less purchased gas cost) is
generally not eroded or enhanced because of gas cost increases or decreases.
The Georgia Public Service Commission and Tennessee Regulatory Authority
have approved Weather Normalization Adjustments ("WNA") that allow the United
Cities Division to increase the base rate portion of customers' bills when
weather is warmer than normal and decrease the base rate when weather is colder
than normal. The net effect of the WNAs was an increase (decrease) in revenues
of $4,394,000, $682,000 and $2,643,000 in 1999, 1998 and 1997, respectively.
20
<PAGE>
The following table sets forth the major rate requests made by the Company
or other parties during the most recent five years and the action taken on such
requests:
Effective Amount Amount
Jurisdiction Date Requested Received
------------ -------- --------- --------
(In thousands)
Texas
West Texas System 11/18/94 $ 2,581 $ 1,702 (a)
11/01/96 7,676 5,800 (a)
Pending 8,827 Pending (g)
Amarillo System Pending 4,354 Pending (g)
Louisiana 11/01/99 (b) - (b)
Kentucky 11/01/95 7,665 2,300 (c)
03/01/96 1,000 (c)
Pending 14,127 Pending (h)
Colorado 05/01/94 4,527 3,246
01/21/98 - (1,600) (e)
Kansas 09/01/95 4,230 2,700 (d)
Missouri 10/14/95 1,100 903
South Carolina 02/07/95 341 253
Tennessee 11/15/95 3,951 2,227
Iowa 05/17/96 750 410
Georgia 12/02/96 5,003 3,160
Illinois 07/09/97 1,234 428
Virginia 09/29/95 810 103
10/01/98 - (248) (f)
(a) These increases include $200,000 and $500,000 applicable to areas outside
the city limits which became effective in January 1995 and April 1997,
respectively.
(b) The Louisiana Public Service Commission approved a Rate Stabilization
Clause ("RSC") for three years with an allowed return on common equity
between 10.5% and 11.5%. This decision increased the service charge
amounts from about 20% to about 70% of actual costs, and increased the
monthly customer charges from $6 to $9, both effective November 1, 1999.
(c) The Kentucky rate order provided an increase of $2,300,000, lowered
depreciation rates effective November 1, 1995 and
21
<PAGE>
provided an additional $1,000,000 beginning March 1, 1996. The order also
included a provision for a pilot demand side management program which could
cost up to $450,000 annually.
(d) This increase applied to the Kansas area previously served by the United
Cities Division and transferred to the Greeley Division in 1999.
(e) Rate reduction as a result of settlement in a case initiated by the
Colorado Consumer Counsel.
(f) Rate reduction as a result of a settlement with the Virginia State
Corporation Commission staff regarding investigation of earnings.
(g) The Energas Division applied for rate increases in August 1999. The
proposed rates have been suspended until December 8, 1999.
(h) The Western Kentucky Gas Division applied for an increase in May 1999. A
hearing is scheduled for December 14, 1999.
COMPETITION
The Company is not currently in significant direct competition with any
other distributors of natural gas to residential and commercial customers within
its service areas. However, the Company does compete with other natural gas
suppliers and suppliers of alternate fuels for sales to industrial and
agricultural customers.
The Company competes in all aspects of its business with alternative energy
sources, including, in particular, electricity. Competition for the residential
and commercial customers is increasing. Promotional incentives, improved
equipment efficiencies, and promotional rates all contribute to the
acceptability of electric equipment. In the United Cities Division, #2 and #6
fuel oil are the primary competition for industrial customers. In addition,
certain customers, primarily industrial, may have the ability to by-pass the
Company's distribution system by connecting directly with a pipeline.
Beginning in 1985, changes in the federal regulatory environment through
Federal Energy Regulatory Commission ("FERC") orders and conditions related to
markets and gas supply in the United States have brought increased competition
into the natural gas industry. In 1993, FERC Order 636 was implemented by the
interstate pipelines that serve the United Cities and Western Kentucky
Divisions, but FERC policies have not had a direct impact upon the Company's
Energas, Greeley and Trans La Divisions which are primarily supplied by
intrastate pipelines. However, competition for large volume customers in the
United Cities and Western Kentucky Divisions and other service areas has
increased as a result of FERC Order 636. The Company has sought regulatory
approvals for competitive pricing on a case by case basis.
22
<PAGE>
The United Cities Division has received approval from all the regulatory
authorities in the states in which it operates, except Iowa, to place into
effect a negotiated tariff rate which allows the United Cities Division to
maintain industrial loads at lower margin rates. Iowa has rules which allow for
flexible rates, which are competitive with the price of alternative fuels. In
addition, certain industrial customers have changed from firm to interruptible
rate schedules in order to obtain natural gas at a lower cost. Additionally,
the United Cities Division has received approval from all state regulatory
authorities to provide transportation service of customer-owned gas.
United Cities Propane Gas, Inc. is in competition with other suppliers of
propane, natural gas and electricity with respect to price and service. The
wholesale cost of propane is subject to fluctuations primarily based on demand,
availability of supply and product transportation costs.
Through its 45% interest in WMLLC, Atmos Energy Marketing, LLC competes
with other natural gas brokers in obtaining natural gas supplies for customers.
Atmos Leasing, Inc. also competes with other companies in the leasing of
real estate, vehicles, and appliances.
Atmos Storage, Inc. charges rates to the United Cities Division that are
subject to review by the various commissions in the states within which the
storage service is provided. Therefore, Storage's rates must be competitive
with other storage facilities. Storage also stores natural gas for WMLLC. As a
result, Storage is in competition with other companies that store natural gas as
to rates charged and deliverability of natural gas. Agreements between Storage
and the United Cities Division give the United Cities Division first priority to
any storage services.
EMPLOYEES
At September 30, 1999, the Company employed 2,062 persons. See "Utility
Sales and Statistical Data by Business Unit - 1999" for the number of employees
by business unit. As discussed in Note 2 of notes to consolidated financial
statements in the Company's Annual Report to Shareholders, the Company underwent
downsizing and restructuring in 1997 and 1998 in connection with the integration
of UCGC and the reorganization of the Company's other divisions.
ITEM 2. PROPERTIES
The Company owns an aggregate of 30,670 miles of underground distribution
and transmission mains throughout its gas distribution systems. These mains are
located on easements or right-of-ways granted to the Company, which generally
provide for perpetual use. The Company maintains its mains through a program of
continuous
23
<PAGE>
inspection and repair and believes that its system of mains is in good
condition. The Company also owns and operates nine propane peak shaving plants
with a total capacity of approximately 1,050,000 gallons that can produce an
equivalent of 19,459 Mcf daily and an LNG storage facility with a capacity of
500,000 Mcf which can inject a daily volume of 30,000 Mcf in the system, as well
as underground storage fields which are used to supplement the supply of natural
gas in periods of peak demand. It has seven underground gas storage facilities
in Kentucky and four in Kansas that have a total storage capacity of
approximately 21.1 Bcf. However, approximately 10.0 Bcf of gas in the storage
facilities must be retained as cushion gas to maintain reservoir pressure. The
maximum daily delivery capability of the storage facilities is approximately 154
MMcf.
Substantially all of the Company's properties in its Greeley Division and
United Cities Division with net values of approximately $173.7 million and
$293.0 million, respectively, are subject to liens under First Mortgage Bonds
assumed by the Company in its mergers with GGC and UCGC. At September 30, 1999,
the liens secured $17.0 million of outstanding 9.4% Series J First Mortgage
Bonds due May 1, 2021, and $102.2 million of outstanding Series N, P, Q, R, T, U
and V First Mortgage Bonds due at various dates from 2000 through 2022.
The Company's administrative offices are consolidated in Dallas, Texas
under one lease. The Company also maintains field offices throughout its
distribution system, the majority of which are located in leased premises.
Net property, plant and equipment at September 30, 1999 included
approximately $918.2 million for utility, $23.8 million for energy services, and
$23.8 million for propane.
The Company holds franchises granted by the incorporated cities and towns
that it serves. At September 30, 1999, the Company held 408 such franchises
having terms generally ranging from five to 25 years. The Company believes that
each of its franchises will be renewed.
ITEM 3. LEGAL PROCEEDINGS
Incorporated by reference from the 1999 Annual Report to Shareholders, Note
6 of notes to consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of fiscal 1999.
24
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of September 30,
1999, regarding the executive officers of the Company. It is followed by a
brief description of the business experience of each executive officer during
the past five years.
Years of
Name Age Service Office Currently Held
- ----------------------------------------------------------------------------
Robert W. Best 52 2 Chairman, President and
Chief Executive Officer
Larry J. Dagley 51 2 Executive Vice President and
Chief Financial Officer
J. Charles Goodman 38 15 Executive Vice President,
Utility Operations
Wynn D. McGregor 46 11 Vice President, Human
Resources
Robert W. Best was named Chairman of the Board, President and Chief
Executive Officer in March 1997. He previously served as Senior Vice President-
Regulated Businesses of Consolidated Natural Gas Company (1996 - March 1997) and
was responsible for its transmission and distribution companies. Prior to that,
he served as Senior Vice President of Transco Energy Company and President of
Transcontinental Gas Pipe Line Corporation (1992-1995); and President of Texas
Gas Transmission Corporation (1985 - 1995).
Larry J. Dagley was named Executive Vice President and Chief Financial
Officer effective May 1, 1997. From August 1995 to May 1997, he served as Senior
Vice President and Chief Financial Officer of Pacific Enterprises, a Los
Angeles, California based utility holding company whose principal subsidiary was
Southern California Gas Co., the nation's largest gas distribution utility. From
1985 until joining Pacific Enterprises, he served as Senior Vice President and
Controller (1985-1993) and Senior Vice President and Chief Financial Officer
(1993-1995) of Transco Energy Company, a Houston, Texas based natural gas
pipeline company. Prior to joining Transco, Mr. Dagley was an audit partner with
Arthur Andersen & Co., where he supervised audits and financial consulting
engagements in the energy industry.
J. Charles Goodman was named Executive Vice President, Operations in April
1995. He previously served as President of the Company's Trans La Gas Division
from February 1993 until April 1995 and as Chief Engineer of the Company from
February 1989 until February 1993.
Wynn D. McGregor was named Vice President, Human Resources in January 1994.
He previously served the Company as Director of Human Resources from February
1991 to December 1993 and as Manager, Compensation and Employment from December
1987 to January 1991.
25
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required by this item is set forth under the caption
"Market Price of Common Stock and Related Matters" in the Financial Review
section of Atmos' 1999 Annual Report to Shareholders filed as Exhibit 13 to this
Annual Report on Form 10-K. Such information is incorporated herein by
reference.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is set forth under the caption
"Selected Financial Data" in the Financial Review section of Atmos' 1999 Annual
Report to Shareholders filed as Exhibit 13 to this Annual Report on Form 10-K.
Such information is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required by this item is set forth under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Financial Review section of Atmos' 1999 Annual Report to
Shareholders filed as Exhibit 13 to this Annual Report on Form 10-K. Such
information is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The risk inherent in the Company's market risk sensitive instruments is the
potential loss arising from adverse changes in natural gas commodity prices and
interest rates as discussed below. The sensitivity analysis does not, however,
consider the effects that such adverse changes may have on overall economic
activity nor do they consider additional actions the Company may take to
mitigate its exposure to such changes. Actual results may differ.
Gas Prices
The Company purchases natural gas for its regulated and non-regulated
natural gas operations. Substantially all of the gas purchased for regulated
operations is recovered through purchased gas adjustment mechanisms. The
Company's market risk in gas prices is related to gas purchases in the open
market at spot prices for sale to non-regulated energy services customers at
fixed prices. As a result, the Company's earnings could be
26
<PAGE>
affected by changes in the price and availability of such gas. As market
conditions dictate, the Company from time to time will lock-in future gas
prices, using various hedging techniques including swap agreements with
suppliers. The Company does not use such financial instruments for trading
purposes and is not a party to any leveraged derivatives. Market risk is
estimated as a hypothetical 10% increase in the portion of the Company's gas
cost related to fixed-price non-regulated sales. Based on projected fiscal 2000
non-regulated gas sales at fixed prices, such an increase would result in an
increase to cost of gas of approximately $2.8 million in fiscal 2000, before
considering the effect of swap agreements outstanding as of September 30, 1999.
As of September 30, 1999, the Company had entered into swap agreements to lock
in gas costs for all outstanding fixed-price sales agreements. The Company plans
to mitigate the risk of increased gas purchase costs for fixed-price customers
by entering into swap agreements to lock in purchased gas cost for estimated
sales volumes in fiscal 2000.
Interest Rates
The Company's earnings are affected by changes in short-term interest rates
as a result of its issuance of short-term commercial paper. If market interest
rates for commercial paper average 2% more in fiscal 2000 than they did during
fiscal 1999, the Company's interest expense, would increase by approximately
$2.0 million.
Market risk for fixed-rate long-term obligations is estimated as the
potential increase in fair value resulting from a hypothetical one percent
decrease in interest rates and amounts to approximately $31.6 million based on
discounted cash flow analyses.
As of September 30, 1999, the Company was not engaged in other activities
which would cause exposure to the risk of material earnings or cash flow loss
due to changes in interest rates, foreign currency exchange rates, or market
commodity prices.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this Item is submitted as a separate section of this
Annual Report on Form 10-K on page 33.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
27
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding directors and compliance with Section 16(a) of the
Securities Exchange Act of 1934 is incorporated herein by reference from the
Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on
February 9, 2000. Information regarding executive officers is included in Part I
of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 9, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 9, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 9, 2000.
28
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial statements and financial statement schedules.
The response to this portion of Item 14 is submitted as a separate section
of this Annual Report on Form 10-K on page 33.
3. Exhibits
The exhibits listed in the accompanying Exhibits Index are filed as part of
this Annual Report on Form 10-K. The exhibits numbered 10.21(a) through 10.32
are management contracts or compensatory plans or arrangements.
(b) Reports on Form 8-K
(1) The Company did not file a Form 8-K Current Report in the quarter ended
September 30, 1999.
29
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ATMOS ENERGY CORPORATION
(Registrant)
By /s/ LARRY J. DAGLEY
------------------------
Larry J. Dagley
Executive Vice President
and Chief Financial
Officer
Date: December 14, 1999
30
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below hereby constitutes and appoints Robert W. Best and Larry J. Dagley, or
either of them acting alone or together, as his true and lawful attorney-in-fact
and agent with full power to act alone, with full power of substitution and
resubstitution, for him and in his name, place and stead, in any and all
capacities, to sign any and all amendments to this Form 10-K, and to file the
same, with all exhibits thereto, and all other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorney-in-fact and agent full power and authority to do and perform each and
every act and thing requisite and necessary to be done, as fully to all intents
and purposes as he might or could do in person, hereby ratifying and confirming
all that said attorney-in-fact and agent, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated:
/s/ ROBERT W. BEST Chairman, President December 14, 1999
- ------------------------- and Chief Executive
Robert W. Best Officer
/s/ LARRY J. DAGLEY Executive Vice December 14, 1999
- ------------------------- President and Chief
Larry J. Dagley Financial Officer
/s/ TOM S. HAWKINS, JR. Vice President, December 14, 1999
- ------------------------- Planning and Budgeting
Tom S. Hawkins, Jr. and Interim Controller
(Principal Accounting
Officer)
31
<PAGE>
/s/ TRAVIS W. BAIN, II Director December 14, 1999
- -------------------------
Travis W. Bain, II
/s/ DAN BUSBEE Director December 14, 1999
- -------------------------
Dan Busbee
/s/ RICHARD W. CARDIN Director December 14, 1999
- -------------------------
Richard W. Cardin
/s/ THOMAS J. GARLAND Director December 14, 1999
- -------------------------
Thomas J. Garland
/s/ GENE C. KOONCE Director December 14, 1999
- -------------------------
Gene C. Koonce
/s/ VINCENT J. LEWIS Director December 14, 1999
- -------------------------
Vincent J. Lewis
/s/ THOMAS C. MEREDITH Director December 14, 1999
- -------------------------
Thomas C. Meredith
/s/ PHILLIP E. NICHOL Director December 14, 1999
- -------------------------
Phillip E. Nichol
/s/ CARL S. QUINN Director December 14, 1999
- -------------------------
Carl S. Quinn
/s/ CHARLES K. VAUGHAN Director December 14, 1999
- -------------------------
Charles K. Vaughan
/s/ RICHARD WARE II Director December 14, 1999
- -------------------------
Richard Ware II
32
<PAGE>
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
(Item 8, 14(a) 1 and 2)
Form 10-K
Page no.
---------
Financial statements and supplementary data:
Consolidated balance sheets at
September 30, 1999 and 1998
(Contained in Exhibit 13)
Consolidated statements of income for
the years ended September 30, 1999, 1998 and 1997
(Contained in Exhibit 13)
Consolidated statements of shareholders' equity for
the years ended September 30, 1999, 1998 and 1997
(Contained in Exhibit 13)
Consolidated statements of cash flows for
the years ended September 30, 1999, 1998 and 1997
(Contained in Exhibit 13)
Notes to consolidated financial statements
(Contained in Exhibit 13)
Supplementary Quarterly Financial Data (unaudited)
(Contained in Exhibit 13)
Independent auditors' report
(Contained in Exhibit 13)
Financial statement schedule for the years ended
September 30, 1999, 1998 and 1997:
II. Valuation and Qualifying Accounts 34
All other financial statement schedules are omitted because the required
information is not present, or not present in amounts sufficient to require
submission of the schedule, or because the information required is included in
the financial statements and accompanying notes thereto.
The financial statements and the independent auditors' report of Ernst &
Young LLP listed in the above index, which are included in the Financial Review
section of the Annual Report to Shareholders of Atmos Energy Corporation for the
year ended September 30, 1999, are incorporated herein by reference.
33
<PAGE>
Atmos Energy Corporation
Schedule II
Valuation and Qualifying Accounts
Three Years Ended September 30, 1999
(In thousands)
<TABLE>
<CAPTION>
Additions
Balance at ---------------------- Balance
beginning Charged to Charged to at end
of costs & other of
period expenses accounts Deductions period
---------- ---------------------- ----------- -------
<S> <C> <C> <C> <C> <C>
1999
- ----
Allowance for doubtful accounts $1,969 $8,899 - $1,637 (1) $9,231
1998
- ----
Allowance for doubtful accounts $2,188 $2,140 - $2,359 (1) $1,969
1997
- ----
Allowance for doubtful accounts $2,462 $2,003 - $2,277 (1) $2,188
</TABLE>
(1) Uncollectible accounts written off
34
<PAGE>
EXHIBITS INDEX
Item 14. (a) (3)
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
------- ------------------------------- ---------------------
Plan of Reorganization
----------------------
<S> <C> <C>
2.1 Agreement and Plan of Reorganization dated July 19, Exhibit 2.1 to Registration
1996, by and between the Registrant and United Statement on Form S-4 filed
Cities Gas Company October 4, 1996 (File No.
333-13429)
2.2 Amendment No. 1 to Agreement and Plan of Exhibit 2.1(a) to Registration
Reorganization dated October 3, 1996 Statement on Form S-4 filed
October 4, 1996 (File No.
333-13429)
Articles of Incorporation and Bylaws
------------------------------------
3.1(a) Restated Articles of Incorporation of the Company, Exhibit 3.1 of Form 10-K for
as Amended (as of July 31, 1997) fiscal year ended September 30,
1997 (File No. 1-10042)
3.1(b) Articles of Amendment to the Restated Articles of Exhibit 3a of Form 10-Q for
Incorporation of Atmos Energy Corporation as quarter ended March 31, 1999 (File
Amended (Texas) No. 1-10042)
3.1(c) Articles of Amendment to the Restated Articles of Exhibit 3b of Form 10-Q for
Incorporation of Atmos Energy Corporation as quarter ended March 31, 1999 (File
Amended (Virginia) No. 1-10042)
3.2 Bylaws of the Company (Amended and Restated as of Exhibit 3.2 of Form 10-K for
November 12, 1997) fiscal year ended September 30,
1997 (File No. 1-10042)
</TABLE>
35
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
- --------- ------------------------------ ------------------------
Instruments Defining Rights of Security Holders
-----------------------------------------------
<S> <C> <C>
4.1 Specimen Common Stock Certificate (Atmos Energy Exhibit (4)(b) of Form 10-K for
Corporation) fiscal year ended September 30,
1988 (File No. 1-10042)
4.2 Rights Agreement, dated as of November 12, 1997, Exhibit 4.1 of Form 8-K dated
between the Company and BankBoston, N.A. November 12, 1997 (File no.
1-10042)
4.3 First Amendment to Rights Agreement dated as of Exhibit 2 of Form 8-A, Amendment
August 11, 1999, between the Company and No. 1, dated August 12, 1999 (File
BankBoston, N.A., as Rights Agent No. 1-10042)
9 Not Applicable
Material Contracts
------------------
10.1(a) Note Purchase Agreement, dated as of December 21, Exhibit 10(c) of Form 8-K filed
1987, by and between the Company and John Hancock January 7, 1988 (File No. 0-11249)
Mutual Life Insurance Company
Note Purchase Agreement, dated as of December 21,
1987, by and between the Company and John Hancock
Charitable Trust I (Agreement is identical to
Hancock Agreement listed above except as to the
parties thereto.)
</TABLE>
36
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------------ ----------------------
<S> <C> <C>
Note Purchase Agreement dated as of December
21, 1987, by and between the Company and Mellon
Bank, N.A., Trustee under Master Trust
Agreement of AT&T Corporation, dated January 1,
1984, for Employee Pension Plans - AT&T - John
Hancock - Private Placement (Agreement is
identical to Hancock Agreement listed above
except as to the parties thereto.)
10.1(b) Amendment to Note Purchase Agreement, dated Exhibit (10)(b)(ii) of Form 10-K
October 11, 1989, by and between the Company for fiscal year ended September
and John Hancock Mutual Life Insurance Company 30, 1989
revising Note Purchase Agreement dated December (File No. 1-10042)
21, 1987
Amendment to Note Purchase Agreement, dated
October 11, 1989, by and between the Company
and John Hancock Charitable Trust I revising
Note Purchase Agreement dated December 21,
1987. (Amendment is identical to Hancock
amendment listed above except as to the parties
thereto.)
</TABLE>
37
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------- ----------------------
<S> <C> <C>
Amendment to Note Purchase Agreement, dated
October 11, 1989, by and between the Company
and Mellon Bank, N.A., Trustee under Master
Trust Agreement of AT&T Corporation, dated
January 1, 1984, for Employee Pension Plans -
AT&T - John Hancock - Private Placement
revising Note Purchase Agreement dated
December 21, 1987 (Amendment is identical to
Hancock amendment listed above except as to
the parties thereto.)
10.1(c) Amendment to Note Purchase Agreement, dated Exhibit 10(b)(iii) of Form 10-K
November 12, 1991, by and between the Company for fiscal year ended September
and John Hancock Mutual Life Insurance Company 30, 1991 (File No. 1-10042)
revising Note Purchase Agreement dated December
21, 1987
Amendment to Note Purchase Agreement, dated
November 12, 1991, by and between the Company
and John Hancock Charitable Trust I revising
Note Purchase Agreement dated December 21,
1987. (Amendment is identical to Hancock
amendment listed above except as to the parties
thereto.)
</TABLE>
38
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------- ----------------------
<S> <C> <C>
Amendment to Note Purchase Agreement, dated
November 12, 1991, by and between the Company
and Mellon Bank, N.A., Trustee under Master
Trust Agreement of AT&T Corporation, dated
January 1, 1984, for Employee Pension Plans -
AT&T - John Hancock - Private Placement
revising Note Purchase Agreement dated December
21, 1987. (Amendment is identical to Hancock
amendment above except as to the parties
thereto.)
10.1(d) Amendment to Note Purchase Agreement, dated Exhibit 4.3(d) to Registration
December 22, 1993, by and between the Company Statement on Form S-3 filed April
and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated December
21, 1987
Amendment to Note Purchase Agreement, dated
December 22, 1993, by and between the Company
and Mellon Bank, N.A., Trustee under Master
Trust Agreement of AT&T Corporation, dated
January 1, 1982, for Employee Pension Plans -
AT&T - John Hancock - Private Placement
revising Note Purchase Agreement dated December
21, 1987 (Amendment is identical to Hancock
amendment listed above except as to the parties
thereto and the amounts thereof)
</TABLE>
39
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------------ ----------------------
<S> <C> <C>
10.1(e) Amendment to Note Purchase Agreement, dated Exhibit 4.3(e) to Registration
December 20, 1994, by and between the Company Statement on Form S-3 filed April
and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated December
21, 1987
Amendment to Note Purchase Agreement, dated
December 20, 1994, by and between the Company
and Mellon Bank, N.A., Trustee under Master
Trust Agreement of AT&T Corporation, dated
January 1, 1984, for Employee Pension Plans -
AT&T - John Hancock - Private Placement
revising Note Purchase Agreement dated December
21, 1987 (Amendment is identical to Hancock
amendment listed above)
10.1(f) Amendment to Note Purchase Agreement, dated Exhibit 4.3(f) to Registration
July 29, 1997, by and between the Company and Statement on Form S-3 filed April
John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated December
21, 1987
</TABLE>
40
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Reference to
-------- ------------------------------------------------ ----------------------
<S> <C> <C>
Amendment to Note Purchase Agreement, dated
July 29,1997, by and between the Company and
Mellon Bank, N.A., Trustee under Master Trust
Agreement of AT&T Corporation, dated January 1,
1984, for Employee Pension Plans - AT&T - John
Hancock - Private Placement revising Note
Purchase Agreement dated December 21, 1987
(Amendment is identical to Hancock amendment
listed above except as to the parties thereto
and the amounts thereof)
10.2(a) Note Purchase Agreement, dated as of October Exhibit 10(c) of Form 10-K for
11, 1989, by and between the Company and John fiscal year ended September 30,
Hancock Mutual Life Insurance Company 1989 (File No. 1-10042)
10.2(b) Amendment to Note Purchase Agreement, dated as Exhibit 10(c)(ii) of Form 10-K for
of November 12, 1991, by and between the fiscal year ended September 30,
Company and John Hancock Mutual Life Insurance 1991 (File No. 1-10042)
Company revising Note Purchase Agreement dated
October 11, 1989
10.2(c) Amendment to Note Purchase Agreement, dated Exhibit 4.4(c) to Registration
December 22, 1993, by and between the Company Statement on Form S-3 filed April
and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated October
11, 1989
</TABLE>
41
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ---------------------------------------------- ----------------------
<S> <C> <C>
10.2(d) Amendment to Note Purchase Agreement, dated Exhibit 4.4(d) to Registration
December 20,1994, by and between the Company Statement on Form S-3 filed April
and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated October
11, 1989
10.2(e) Amendment to Note Purchase Agreement, dated Exhibit 4.4(e) to Registration
July 29, 1997, by and between the Company and Statement on Form S-3 filed April
John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated October
11, 1989
10.3(a) Note Purchase Agreement, dated as of August 29, Exhibit 10(f)(i) of Form 10-K for
1991, by and between the Company and The fiscal year ended September 30,
Variable Annuity Life Insurance Company 1991 (File No. 1-10042)
10.3(b) Amendment to Note Purchase Agreement, dated Exhibit 10(f)(ii) of Form 10-K for
November 26, 1991, by and between the Company fiscal year ended September 30,
and The Variable Annuity Life Insurance Company 1991 (File No. 1-10042)
revising Note Purchase Agreement dated August
29, 1991
10.3(c) Amendment to Note Purchase Agreement, dated Exhibit 4.5(c) to Registration
December 22, 1993, by and between the Company Statement on Form S-3 filed April
and The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated August
29, 1991
</TABLE>
42
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------- ----------------------
<S> <C> <C>
10.3(d) Amendment to Note Purchase Agreement, dated Exhibit 4.5(d) to Registration
July 29, 1997, by and between the Company and Statement on Form S-3 filed April
The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated August
29, 1991
10.4(a) Note Purchase Agreement, dated as of August 31, Exhibit (10)(f) of Form 10-K for
1992, by and between the Company and The fiscal year ended September 30,
Variable Annuity Life Insurance Company 1992 (File No. 1-10042)
10.4(b) Amendment to Note Purchase Agreement, dated Exhibit 4.6(b) to Registration
December 22, 1993, by and between the Company Statement on Form S-3 filed April
and The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated August
31, 1992
10.4(c) Amendment to Note Purchase Agreement, dated Exhibit 4.6(c) to Registration
July 29, 1997, by and between the Company and Statement on Form S-3 filed April
The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477)
revising Note Purchase Agreement dated August
31, 1992
10.5(a) Note Purchase Agreement, dated November 14, Exhibit 10.1 of Form 10-Q for
1994, by and among the Company and New York quarter ended December 31, 1994
Life Insurance Company, New York Life Insurance (File No. 1-10042)
and Annuity Corporation, The Variable Annuity
Life Insurance Company, American General Life
Insurance Company, and Merit Life Insurance
Company
</TABLE>
43
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------ ----------------------
<S> <C> <C>
10.5(b) Amendment to Note Purchase Agreement, dated Exhibit 4.7(b) to Registration
July 29, 1997 by and among the Company and New Statement on Form S-3 filed April
York Life Insurance Company, New York Life 20, 1998 (File No. 333-50477)
Insurance and Annuity Corporation, The Variable
Annuity Life Insurance Company, American
General Life Insurance Company and Merit Life
Insurance Company revising Note Purchase
Agreement dated November 14, 1994
10.6(a) Indenture of Mortgage, dated as of July 15, Exhibit to Registration Statement
1959, from United Cities Gas Company to First of United Cities Gas Company on
Trust of Illinois, National Association, and Form S-3 (File No. 33-56983)
M.J. Kruger, as Trustees, as amended and
supplemented through December 1, 1992 (the
Indenture of Mortgage through the 20th
Supplemental Indenture)
10.6(b) Twenty-First Supplemental Indenture dated as of Exhibit 10.7(a) of Form 10-K for
February 5, 1997 by and among United Cities Gas fiscal year ended September 30,
Company and Bank of America Illinois and First 1997 (File No. 1-10042)
Trust National Association and Russell C.
Bergman supplementing Indenture of Mortgage
dated as of July 15, 1959
</TABLE>
44
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- --------------------------------------------- ----------------------
<S> <C> <C>
10.6(c) Twenty-Second Supplemental Indenture dated as Exhibit 10.7(b) of Form 10-K for
of July 29, 1997 by and among the Company and fiscal year ended September 30,
First Trust National Association and Russell C. 1997 (File No. 1-10042)
Bergman supplementing Indenture of Mortgage
dated as of July 15, 1959
10.7(a) Form of Indenture between United Cities Gas Exhibit to Registration Statement
Company and First Trust of Illinois, National of United Cities Gas Company on
Association, as Trustee dated as of November Form S-3 (File No. 33-56983)
15, 1995
10.7(b) First Supplemental Indenture between the Exhibit 10.8(a) of Form 10-K for
Company and First Trust of Illinois, National fiscal year ended September 30,
Association, as Trustee dated as of July 29, 1997 (File No. 1-10042)
1997
10.8(a) Seventh Supplemental Indenture, dated as of Exhibit 10.1 of Form 10-Q for
October 1, 1983 between Greeley Gas Company quarter ended June 30, 1994 (File
("Greeley Division") and the Central Bank of No. 1-10042)
Denver, N.A. ("Central Bank")
10.8(b) Ninth Supplemental Indenture, dated as of April Exhibit 10.2 of Form 10-Q for
1, 1991, between the Greeley Division and quarter ended June 30, 1994 (File
Central Bank No. 1-10042)
10.8(c) Bond Purchase Agreement, dated as of April 1, Exhibit 10.3 of Form 10-Q for
1991, between the Greeley Division and Central quarter ended June 30, 1994 (File
Bank No. 1-10042)
</TABLE>
45
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------ ----------------------
<S> <C> <C>
10.8(d) Tenth Supplemental Indenture, dated as of Exhibit 10.4 of Form 10-Q for
December 1, 1993, between the Company and quarter ended June 30, 1994 (File
Colorado National Bank, formerly Central Bank No. 1-10042)
10.9(a) Purchase Agreement for 6-3/4% Debentures due Exhibit 99.1 of Form 8-K dated
2028 by and among Merrill Lynch Co., July 22, 1998 (File No. 1-10042)
NationsBanc Montgomery Securities LLC, Edward
D. Jones & Co., L.P. and Atmos Energy
Corporation dated July 22, 1998
10.9(b) Form of Indenture between Atmos Energy Exhibit 4.1 to Registration
Corporation and U.S. Bank Trust National Statement on Form S-3 filed April
Association, Trustee 20, 1998 (File No. 333-50477)
Gas Supply Contracts
--------------------
10.10(a) Firm Gas Transportation Agreement No. 123535
dated November 1, 1998 between Greeley Gas and
Public Service Company of Colorado
10.10(b) Transportation Storage Service Agreement No. Exhibit 10.6(b) of Form 10-K for
TA-0544 between Greeley Gas and Williams fiscal year ended September 30,
Natural Gas Company dated October 1, 1993 1994 (File No. 1-10042)
10.10(c) Firm Transportation Service Agreement No. Exhibit 10.10(d) of Form 10-K for
33180A, Rate Schedule TF-1, between Greeley Gas fiscal year ended September 30,
Company and Colorado Interstate Gas Company, 1998 (File No. 1-10042)
dated July 1, 1998.
</TABLE>
46
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------------- ----------------------
<S> <C> <C>
10.10(d) Firm Transportation Service Agreement No.
33181A, Rate Schedule TF-1, between Colorado
Interstate Gas Company and Greeley Gas Company
dated July 1, 1998
10.10(e) No-Notice Storage and Transportation Delivery Exhibit 10.10(e) of Form 10-K for
Service Agreement No. 31028A, Rate Schedule fiscal year ended September 30,
NNT-1, between Colorado Interstate Gas Company 1998 (File No. 1-10042)
and Greeley Gas Company dated October 1, 1996
10.11 Amarillo Supply Agreement dated January 2, 1993 Exhibit 10.7(a) of Form 10-K for
between Energas and Pioneer Natural Resources, fiscal year ended September 30,
USA, Inc. (formerly Mesa Operating Company) 1994 (File No. 1-10042)
10.12(a) Agreement for Firm Intrastate Transportation of Exhibit 10.1 of Form 10-Q for
Natural Gas in the State of Louisiana between quarter ended March 31, 1998
Trans La and Louisiana Intrastate Gas Company (File No. 1-10042)
L.L.C. (LIG) dated December 22, 1997 and
effective July 1, 1997
10.12(b) Agreement for Firm 311(a)(2) Transportation of Exhibit 10.2 of Form 10-Q for
Natural Gas in the State of Louisiana between quarter ended March 31, 1998
Trans La and Louisiana Intrastate Gas Company (File No. 1-10042)
L.L.C. (LIG) dated December 22, 1997 and
effective July 1, 1997
10.13(a) Gas Transportation Agreement between Texas Gas Exhibit 10.3 of Form 10-Q for
and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993
(Contract no. T3355, zone 3) (File No. 1-10042)
</TABLE>
47
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
--------- ---------------------------------------------- -------------------------
<S> <C> <C>
10.13(b) Gas Transportation Agreement between Texas Gas Exhibit 10.4 of Form 10-Q for
and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993
(Contract no. T3819, zone 4) (File No. 1-10042)
10.13(c) Gas Transportation Agreement between Texas Gas Exhibit 10.5 of Form 10-Q for
and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993
(Contract no. N0210, zone 2, Contract no. (File No. 1-10042)
N0340, zone 3, Contract no. N0435, zone 4)
10.14(a) Gas Transportation Agreement, Contract No. Exhibit 10.17(a) of Form 10-K for
2550, dated September 1, 1993, between fiscal year ended September 30,
Tennessee Gas Pipeline Company, a division of 1993 (File No. 1-10042)
Tenneco, Inc. ("Tennessee Gas"), and Western
Kentucky, Campbellsville Service Area
10.14(b) Gas Transportation Agreement, Contract No. Exhibit 10.17(b) of Form 10-K for
2546, dated September 1, 1993, between fiscal year ended September 30,
Tennessee Gas and Western Kentucky, Danville 1993 (File No. 1-10042)
Service Area
10.14(c) Gas Transportation Agreement, Contract No. Exhibit 10.17(c) of Form 10-K for
2385, dated September 1, 1993, between fiscal year ended September 30,
Tennessee Gas and Western Kentucky, Greensburg 1993 (File No. 1-10042)
et al Service Area
10.14(d) Gas Transportation Agreement, Contract No. Exhibit 10.17(d) of Form 10-K for
2551, dated September 1, 1993, between fiscal year ended September 30,
Tennessee Gas and Western Kentucky, Harrodsburg 1993 (File No. 1-10042)
Service Area
</TABLE>
48
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------------- ----------------------
<S> <C> <C>
10.14(e) Gas Transportation Agreement, Contract No. Exhibit 10.17(e) of Form 10-K for
2548, dated September 1, 1993, between fiscal year ended September 30,
Tennessee Gas and Western Kentucky, Lebanon 1993 (File No. 1-10042)
Service Area
10.15 Gas Service Agreement (Service for Firm Exhibit 10.5 of Form 10-Q for
Transportation) between Energas and Westar quarter ended December 31, 1996
Transmission Company dated January 1, 1996 (File No. 1-10042)
10.16 Gas Service Agreement (Service for Firm Exhibit 10.7 of Form 10-Q for
Transportation) between Westar Transmission quarter ended December 31, 1996
Company and EnerMart dated January 1, 1996 (File No. 1-10042)
(Irrigation)
10.17 Gas Service Agreement (Service for Firm Exhibit 10.8 of Form 10-Q for
Transportation) between KN Westex and Enermart quarter ended December 31, 1996
Trust dated January 1, 1996 (File No. 1-10042)
10.18 Gas Sales Agreement (Irrigation) between KN Exhibit 10.11 of Form 10-Q for
Marketing and EnerMart Trust dated March 1, 1996 quarter ended December 31, 1996
(File No. 1-10042)
10.19 Gas Sales Agreement (Swing) between Energas and Exhibit 10.13 of Form 10-Q for
KN Marketing, dated January 1, 1996 quarter ended December 31, 1996
(File No. 1-10042)
10.20(a) Operating Agreement between Energas and Westar Exhibit 10.15 of Form 10-Q for
Transmission Company, effective December 1, 1996 quarter ended December 31,
1996(File No. 1-10042)
</TABLE>
49
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------------- ----------------------
<S> <C> <C>
10.20(b) Gas Transportation Agreement Service Package Exhibit 10.4 of Form 10-Q for
No. 4272 between United Cities Gas Company and quarter ended March 31, 1998(File
East Tennessee Natural Gas Company dated No. 1-10042)
November 1, 1993
10.20(c) Gas Transportation Agreement Service Package Exhibit 10.5 of Form 10-Q for
No. 4219 between United Cities Gas Company and quarter ended March 31, 1998(File
Tennessee Gas Pipeline Company dated November No. 1-10042)
1, 1993
10.20(d) Transportation-Storage Contract No. TA-0614 Exhibit 10.6 of Form 10-Q for
(Request 0180) between United Cities Gas quarter ended March 31, 1998(File
Company and Williams Natural Gas Company dated No. 1-10042)
October 1, 1993
10.20(e) Transportation-Storage Contract No. TA-0611 Exhibit 10.7 of Form 10-Q for
(Request 0002) between United Cities Gas quarter ended March 31, 1998(File
Company and Williams Natural Gas Company dated No. 1-10042)
October 1, 1993
10.20(f) Service Agreement No. 867760 Under Rate Exhibit 10.8 of Form 10-Q for
Schedule FT between United Cities Gas Company quarter ended March 31, 1998(File
and Southern Natural Gas Company dated November No. 1-10042)
1, 1993
10.20(g) Service Agreement No. 867761 Under Rate Exhibit 10.9 of Form 10-Q for
Schedule FT-NN between United Cities Gas quarter ended March 31, 1998(File
Company and Southern Natural Gas Company dated No. 1-10042)
November 1, 1993
</TABLE>
50
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- --------------------------------------------- ----------------------
<S> <C> <C>
Executive Compensation Plans and Arrangements
---------------------------------------------
10.21(a) *Severance Agreement dated April 1, 1995 Exhibit 10.3 of Form 10-Q for
between the Company and J. Charles Goodman quarter ended June 30, 1995 (File
No. 1-10042)
10.21(b) *Form of Atmos Energy Corporation Change in Exhibit 10.21(b) of Form 10-K for
Control Severance Agreement--Tier I fiscal year ended September 30,
1998 (File No. 1-10042)
10.21(c) *Form of Atmos Energy Corporation Change in Exhibit 10.21(c) of Form 10-K for
Control Severance Agreement--Tier II fiscal year ended September 30,
1998 (File No. 1-10042)
10.22(a) *Atmos Energy Corporation Mini-Med Plan, as Exhibit 10.22 of Form 10-K for
restated effective July 1, 1996 fiscal year ended September 30,
1996 (File No. 1-10042)
10.22(b) *Amendment No. One to the Atmos Energy Exhibit 10.22(b) of Form 10-K for
Corporation Mini-Med Plan fiscal year ended September 30,
1998 (File No. 1-10042)
10.23 *Long Term Stock Plan for the United Cities Gas Exhibit 99.1 of Form S-8 filed
Company Division July 29, 1997 (File No. 333-32343)
10.24(a) *Atmos Energy Corporation Retirement Plan for Exhibit 10(y) of Form 10-K for
Outside Directors fiscal year ended September 30,
1992 (File No. 1-10042)
</TABLE>
51
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- -------------------------------------------- ------------------------
<S> <C> <C>
10.24(b) *Amendment No. 1 to the Atmos Energy Exhibit 10.2 of Form 10-Q for
Corporation Retirement Plan for Outside quarter ended December 31, 1996
Directors (File No. 1-10042)
10.25(a) *Description of Financial and Estate Planning Exhibit 10.25(b) of Form 10-K for
Program fiscal year ended September 30,
1997 (File No. 1-10042)
10.25(b) *Description of Sporting Events Program Exhibit 10.26(c) of Form 10-K for
fiscal year ended September 30,
1993 (File No. 1-10042)
10.26(a) *Atmos Energy Corporation Supplemental Exhibit 10.26 of Form 10-K for
Executive Benefits Plan, Amended and Restated fiscal year ended September 30,
in its Entirety August 12, 1998 1998 (File No. 1-10042)
10.26(b) *Atmos Energy Corporation Performance-Based Exhibit 10.32 of Form 10-K for
Supplemental Executive Benefits Plan, Effective fiscal year ended September 30,
Date August 12, 1998 1998 (File No. 1-10042)
10.27 *Atmos Energy Corporation Restricted Stock Exhibit 10.27 of Form 10-K for
Grant Plan (Amended and Restated as of November fiscal year ended Septmeber 30,
12, 1997) 1997 (File No. 1-10042)
</TABLE>
52
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------------- ----------------------
<S> <C> <C>
10.28 *Atmos Energy Corporation Outside Directors Exhibit 10.28 of Form 10-K fiscal
Stock-for-Fee Plan (Amended and Restated as of year ended September 30, 1997
November 12, 1997) (File No. 1-10042)
10.29 *Atmos Energy Corporation Executive Exhibit 10.33 of Form 10-K for
Nonqualified Deferred Compensation Plan fiscal year ended September 30,
1998 (File No. 1-10042)
10.30(a) *Consulting Agreement between the Company and Exhibit 10.2 of Form 10-Q for
Charles K. Vaughan, effective October 1, 1994 quarter ended June 30, 1997 (File
No. 1-10042)
10.30(b) *Amendment No.1 to Consulting Agreement between Exhibit 10.3 of Form 10-Q for
the Company and Charles K. Vaughan, dated May quarter ended June 30, 1997 (File
14, 1997 No. 1-10042)
10.30(c) *Amendment No. 2 to Consulting Agreement Exhibit 10.30(c) of Form 10-K for
between the Company and Charles K. Vaughan, fiscal year ended September 30,
dated August 12, 1998 1998 (File No. 1-10042)
10.30(d) *Amendment No. 3 to Consulting Agreement
between the Company and Charles K. Vaughan,
dated November 10, 1999
10.31(a) *Atmos Energy Corporation Executive Retiree Exhibit 10.31 of Form 10-K for
Life Plan fiscal year ended September 30,
1997 (File No. 1-10042)
</TABLE>
53
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- --------------------------------------------- ----------------------
<S> <C> <C>
10.31(b) *Amendment No. 1 to The Atmos Energy Exhibit 10.31(a) of Form 10-K for
Corporation Executive Retiree Life Plan fiscal year ended September 30,
1997 (File No. 1-10042)
10.32 *Atmos Energy Corporation Equity Incentive and Exhibit 99.1 of Form S-8 filed
Deferred Compensation Plan for Non-Employee March 1, 1999 (File No. 333-73145)
Directors
11 Not applicable
12 Not applicable
13 Financial Review section of the Company's 1999
Annual Report to Shareholders (with exception
of the information incorporated by reference
included in Part I and Part II hereof, the 1999
Annual Report to Shareholders is not deemed
filed or part of this Form 10-K)
16 Not applicable
18 Not applicable
Other Exhibits, as indicated
----------------------------
21 Subsidiaries of the registrant
22 Not applicable
23 Consent of independent auditor, Ernst & Young
LLP
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ----------------------------------------------- ----------------------
<S> <C> <C>
24 Power of Attorney Signature page of Form 10-K for
fiscal year ended September 30,
1999
27 Financial Data Schedule for Atmos for year
ended September 30, 1999
</TABLE>
--------------------------
* This exhibit constitutes a "management contract or compensatory plan,
contract, or arrangement."
55
<PAGE>
EXHIBIT 10.10(a)
FIRM GAS TRANSPORTATION SERVICE AGREEMENT
Contract No. 123535
THIS SERVICE AGREEMENT (Agreement), made and entered into as of this 1st
day of November, 1998, by and between Public Service Company of Colorado
(Company), a Colorado corporation, having a mailing address of P.O. Box 840,
Denver, Colorado, 80202, and Greeley Gas Company, a Division of Atmos Energy
Corporation (Shipper), a Texas corporation, having a mailing address of 700
Three Lincoln Centre, 5430 LBJ Freeway, P.O. Box 650205, Dallas, Texas 75265-
0205. Company and Shipper are collectively referred to as the "Parties."
THE PARTIES REPRESENT:
Shipper has by separate agreement acquired supplies of natural gas,
hereinafter referred to as "Shipper's Gas;"
Shipper has made the necessary arrangements and/or has entered into
separate agreements to cause Shipper's Gas to be delivered to Company's Receipt
Point(s) as specified in Exhibit(s) "A-1" through "C-2;"
Shipper has requested and Company agrees to receive and transport Shipper's
Gas from the Receipt Point(s) to the Delivery Point(s), as specified in
Exhibit(s) "A-1" through "C-2," on a firm capacity basis and, if applicable, to
sell gas to Shipper on a firm supply reservation basis; and
Shipper assumes responsibility for the installation and maintenance costs
for a communication line necessary for electronic metering for the facility(s)
specified in Exhibit(s) "A-1," "B-1" and "C-1."
THEREFORE, THE PARTIES AGREE AS FOLLOWS:
1. Shipper acknowledges and agrees that gas transportation service
provided hereunder is subject to the terms and conditions of Company's
applicable gas transportation tariff as on file and in effect from time to time
with the Public Utilities Commission of the State of Colorado (Commission) and
such terms and conditions are incorporated herein as part of this Agreement.
2. Rates and Payment: Transportation service, Firm Capacity service and
Firm Supply Reservation service provided by
- 1 -
<PAGE>
Company under this Service Agreement shall be paid for by Shipper at the charges
under the standard rate set forth in Company's gas transportation tariff unless
otherwise specified in Exhibit(s) "A-1" through "C-2." Applicable facility
charges shall be paid at the rate set forth in Company's Gas Transportation
Tariff unless otherwise specified in Exhibit(s) "A-1" through "C-2."
3. Back-up Supply Sales Service: In the event that adequate supplies of
Shipper's gas are not available for receipt by Company, Company shall sell to
Shipper sufficient quantity(s) of natural gas as necessary to meet Shipper's
backup natural gas supply needs, up to the Total Peak Day Quantity for the Firm
Supply Reservation Service (if any) as specified in Exhibit(s) "A-1" through "C-
2," but in no event greater at any Delivery Point than the Firm Capacity Peak
Day Quantity at such Delivery Point as specified in Exhibit(s) "A-1" through "C-
2," except as provided for in paragraph 10 hereof. To the extent that the
Shipper does not purchase Firm Supply Reservation Service or exceeds the Firm
Capacity Peak Day Quantity at any Delivery Point, Company will provide Back-up
Supply Sales Service on an interruptible basis, as available. All natural gas
sold by Company to Shipper shall be at the Back-up Supply Sales Charge specified
in Company's gas transportation tariff.
4. Quality: Gas delivered by the Shipper or for the Shipper's account at
the Receipt Point(s) as specified in Exhibit(s) "A-1" through "C-2" shall
conform to the specifications for gas as specified in Exhibit "D" and Exhibit
"E."
5. Term - Effective Date: This Agreement shall be effective November 1,
1998, and shall continue in full force and effect through April 30, 2003 for all
Delivery Points identified in Exhibit "A-1 and A-2", and April 30, 1999 for all
Delivery Points identified in Exhibits "B-1", "B-2", "C-1" and "C-2" under this
Agreement, and from year to year thereafter until terminated by either party
effective upon such Service Termination Date(s) or May 1 of any succeeding year
upon thirty (30) days prior written notice.
6. Notices: Except as otherwise provided, any notice or information that
either party may desire to give to the other regarding this agreement shall be
in writing to the following address, or to such other address as either of the
parties shall designate in writing.
COMPANY: SHIPPER:
Payments Only: Invoices only
Public Service Greeley Gas Company, a Division of
Company of Colorado
- 2 -
<PAGE>
P.O. Box 17230 Atmos Energy Corporation
Denver, Colorado 80217-0230 Attn: Gas Supply Dept
(303) 623-1234 P.O. Box 650205
Fax: (303) 294-2136 Dallas, Texas 75265-0205
Phone : (972) 855-3756
Fax: (972) 855-3773
All Others
Public Service Greeley Gas Company, a Division of
Company of Colorado
Seventeenth Street Plaza Atmos Energy Corporation
1225 17th Street, Suite 1100 Attn: Gas Supply Dept
Denver, Colorado 80202-5533 P.O. Box 650205
Dallas, Texas 75265-0205
Attn: Unit Manager, Phone: (972) 855-3758
Gas Transportation
Phone: (303) 294-8318 Fax: (972) 855-3773
Fax: (303) 294-2757
Routine communications, including monthly statements and payments, shall be
considered as duly delivered or furnished three (3) days after being mailed or
when transmitted electronically.
7. Assignment - Consent: This Service Agreement shall not be assigned by
either party hereto without the prior written consent of the other party.
Consent for assignment of this Service Agreement shall not be unreasonably
withheld by or from either party.
8. Cancellation of Prior Agreement: This Service Agreement supersedes,
cancels and terminates, as of the date of this Service Agreement, the following
agreements and any amendments thereto:
Gas Transportation Service Agreement, dated 11/1/95 (Document No. 123535),
between Greeley Gas Company, a division of Atmos Energy Company and Public
Service Company of Colorado
9. Cancellation of this Service Agreement: (a) Shipper may cancel this
Service Agreement upon thirty (30) days' written notice. If Receiving Party(s)
then chooses to return to full firm natural gas service from Company, Company
will, at Receiving Party's request, subject to availability of sufficient
volumes of firm natural gas from Company's suppliers, reinstate Receiving Party
with full firm service under the appropriate tariffs as they may be filed with
the Commission. Shipper shall be responsible for costs, if any, which may be
incurred by Company due to such termination.
- 3 -
<PAGE>
(b) In the event Shipper no longer desires Firm Transportation Service and
Receiving Party(s) obtains interruptible sales or interruptible transportation
service or converts to an alternate fuel prior to the end of the Contract Period
or any subsequent Contract Period, Shipper may terminate this Agreement by
paying Company a termination charge. The termination charge shall equal the Firm
Capacity Charge and the Firm Supply Reservation Charge, if applicable,
multiplied by the Receiving Party(s)' Peak Day Quantity(s), as described on
Exhibit(s) "A-1" through "C-2," multiplied by the number of months remaining in
the Contract Period. The parties agree that Shipper shall owe no termination
charge in the event the Agreement is terminated in accordance with paragraph 5
above.
(c) Either party shall have the further right to terminate this Agreement
if the other party, within ten days following receipt of written notification of
a claim of a material breach hereunder, fails to remedy such material breach and
to indemnify such party for the consequences thereof. Such termination shall
become effective on the eleventh day following such notification or, if the
notification provides for a different termination date which is later than the
ten-day notification period, on the date specified in such notification. For
purposes of this paragraph, "material breach" shall include, but not be limited
to, a continuing or repeated failure to perform a basic obligation under this
Agreement and shall not include periodic or isolated failures to perform or
other liquidated claims which can be resolved pursuant to monetary or volume
adjustments.
10. Delivery Point Peak Day Quantity: (a) The Delivery Points
reflected in the attached Exhibits "A-1" through "C-2" are interconnections
between Company's pipeline system and Shipper's downstream natural gas
facilities and the parties recognize the mutual operational benefits of
providing for flexibility in coordinating gas flows at each of these Delivery
Points. The Peak Day Quantities identified in the attached Exhibits "A-1"
through "C-2" represent Shipper's current and best information of Delivery Point
peaking volumes. Shipper and Company agree that the parties will reevaluate
these volumes on a periodic basis, but at least once annually, to determine if
and at what level any adjustments to the individual Delivery Point Peak Day
Quantities are needed.
(b) On a monthly basis, Company will review the actual deliveries made to
these points and, provided the total volumes delivered do not exceed the total
contracted-for volume applicable to the corresponding Exhibit area, Company will
authorize any volume exceeding the Delivery Point Peak Day Quantity as
authorized overrun gas. Should delivered volumes at any Delivery Point
consistently exceed the Peak Day Quantity for
- 4 -
<PAGE>
that point, Shipper will request and Company will accept, subject to available
capacity, an increase in the contracted-for Peak Day Quantity at the specified
Delivery Point. In increasing the contracted volume at a Receipt Point, Shipper
may shift volumes from other points within the same Exhibit area if volumes at
such other points do not exceed maximum Peak Day Quantities in which case
Shipper may request an increase in the overall Contract Maximum Peak Day
quantity, as necessary.
(c) If, pursuant to any applicable state law or administrative action,
order, or regulation Shipper restructures its gas utility services to provide
unbundled gas sales and transportation services to some or all of its customers,
and such restructuring results in Shipper holding Peak Day Quantities under this
Agreement in excess of that required to provide service to the markets served by
Shipper using the gas transportation service provided under this Agreement
subsequent to such restructuring ("Excess Capacity"), Shipper shall have the
right to reduce the Peak Day Quantities hereunder by the quantity of such Excess
Capacity to the extent Shipper is unable, through the use of its best efforts,
to assign any of such Excess Capacity to third parties or to acquire the
necessary regulatory approvals to permit Shipper to recover the costs of such
Excess Capacity through its service rates or charges. Any such reduction to the
Peak Day Quantities hereunder shall become effective upon the implementation
date of Shipper's restructuring of services. If Shipper elects to exercise its
right to reduce Peak Day Quantities hereunder pursuant to this subsection,
Shipper shall provide Company at least ninety (90) days prior written notice of
such election.
11. Maximum Capacity by Exhibit: Administrative circumstances require the
separation of electronically metered and non-electronically metered volumes into
two separate Exhibits covering the same regional area, as reflected in the
attached Exhibit "A-1" Electronically Metered Front Range and Exhibit "A-2" Non-
Electronically Metered Front Range, Exhibit "B-1" Electronically Metered
Southern and Exhibit "B-2" Non-Electronically Metered Southern, and Exhibit "C-
1" Electronically Metered Western and Exhibit "C-2" Non-Electronically Metered
Western. This Agreement is intended to make available firm transportation
service up to the maximum contracted volume by Exhibit area, i.e., the Front
Range Area (Exhibits "A-1" and "A-2"), the Southern Area (Exhibit "B-1" and "B-
2"), and the Western Area (Exhibits"C-1" and "C-2"). Therefore, in instances
where the total delivered volumes under any Electronically Metered or Non-
Electronically Metered Exhibit exceed the Maximum Daily Contract quantity for
that Exhibit, the parties agree that transportation will be authorized provided
available capacity
- 5 -
<PAGE>
exists on the corresponding Electronically Metered or Non-Electronically Metered
Exhibit area.
12. For all Delivery Points listed on Exhibits "A-2," "B-2" and "C-2,"
Shipper will nominate transportation volumes based on a percentage volume
provided by Company, therefore, the balancing provisions of Company's Tariff as
they would apply to this Agreement are waived.
13. Exhibit(s) and Addendums: All exhibits attached hereto are
incorporated into the terms of this Agreement.
14. This Agreement shall be governed by and construed in accordance with
the laws of the State of Colorado.
IN WITNESS WHEREOF, the parties have executed this Firm Gas Transportation
Service Agreement as of the day and year first above written.
COMPANY: SHIPPER:
PUBLIC SERVICE COMPANY GREELEY GAS COMPANY, A DIVISION
OF COLORADO OF ATMOS ENERGY CORPORATION
By: By:
------------------------ ------------------------
Title: Title:
------------------------ ------------------------
Taxpayer I.D. No. 84-0296600 Taxpayer I.D. No.
- 6 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
GREELEY GAS COMPANY, A DIVISION OF
ATMOS ENERGY CORPORATION (Shipper)
AND
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
- --------------------------------------------------------------------------------
Receipt Point Peak Day Quantity Utilization Curve
Dth/Day
- --------------------------------------------------------------------------------
Chalk Bluffs 39,868 General
- --------------------------------------------------------------------------------
CIG Ft. Lupton 797 General
- --------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Ault #1 & #2 306412692 800 1st meter $185 see below 11/1/98 08/26/90 11/1/98 4/30/2003
- ---------------------------------------------------------------------------------------------------------------------------
Eaton #1 & #2 206412763 500 addt'l $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
Kersey Group 706412713 1,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
Lasalle 406412719 900 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
Lucerne #1 606412723 200 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 7 -
<PAGE>
<TABLE>
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Monfort Meas 706412727 500 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
Statn. meter
- ---------------------------------------------------------------------------------------------------------------------------
North Greeley 106412730 14,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
Platteville 906412745 1000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
South Greeley 106412754 2,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 8 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE
(cont'd.)
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S) continued
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
West Greeley 606412761 18,715 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003
meter
- --------------------------------------------------------------------------------------------------------------------------
CIG/PSCo n/a 8,000 n/a n/a see below 11/1/98 06/01/98 11/1/98 5/31/2003
inter-
connects
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 39,615Dth
3. FIRM SUPPLY RESERVATION SERVICE
Front Range Effective Date Termination Date
Peak Day Quantity Of Service Of Service
Dth/Day
- ---------------------------------------------------------------------
3,005 6/1/98 4/30/2003
- ---------------------------------------------------------------------
Total Firm Supply Reservation Quantity available for delivery to all of
Shipper's Delivery Points as may be nominated from time to time under contract
numbers 123535 and 177473: 3,005 Dth
Rates for Firm Transportation Service:
Unless otherwise specified as provided below, the Transportation Commodity
Charge for services hereunder for all quantities nominated by Shipper and
delivered by Company to the Delivery Points identified above shall be $.05/Dth
inclusive of any Demand Side Management Charges and General Rate Schedule
Adjustments, plus additional surcharges for reimbursement of applicable taxes,
franchise fees and Fuel Reimbursement. The parties further agree that the
percentage for Fuel Reimbursement to be retained by Company for deliveries made
to Front
- 9 -
<PAGE>
Range Delivery Points from PSCo to Shipper under the above referenced
agreements shall be 2%, with 0% fuel deductions for deliveries made by PSCo to
CIG Delivery Points.
The Transportation Commodity Charge provided above shall continue in effect from
November 1, 1998 through April 30, 2003, or in the case of the CIG Delivery
Points, May 31, 2003, unless a revised
- 10 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE
(cont'd.)
discounted or minimum Transportation Commodity Charge applicable to service
hereunder is ordered by the Commission or the Commission issues an order in a
rate proceeding which specifically disallows the Company's proposed recovery in
its jurisdictional rates of the revenue requirement attributable to the
difference between the Transportation Commodity Charge provided above and the
applicable Maximum Transportation Commodity Charge set forth in Company's
tariff, either through a discount adjustment on transportation throughput or
other method of rate recovery. If a revised discounted or minimum
Transportation Commodity Charge applicable to service hereunder is ordered by
the Commission or the Commission issues an order in a rate proceeding
disallowing the Company's proposed recovery of the revenue requirement
attributable to the discount provided hereunder, the parties shall have 30 days
after the date of such to attempt to adjust other components of such total
charge so that there will be no increase in such total charge paid by Shipper
hereunder. If the parties are unable to make any adjustment within the then
existing Commission orders and there is an increase in such total charge paid by
Shipper, Shipper shall pay the increased rate required by the Commission but
shall have the right to terminate this Agreement at any time and,
notwithstanding anything contained herein to the contrary, without any
termination or other charge, thereafter upon 30 days prior written notice to
Company.
Upon the expiration of the term of the discounted Transportation Commodity
Charge, as specified herein, the Transportation Commodity Charge shall
automatically revert to the full Standard Rate as applicable under Company's
then-effective Gas Transportation Tariff, as approved and on file with the
Commission. A minimum of ninety days prior to April 30, 2003, Shipper may
request a price redetermination for the discounted rate provided above. The
parties shall endeavor to reach a mutually agreeable rate prior to May 1, 2003
to be effective prospectively thereafter. If no such redetermined rate can be
agreed upon, either party may terminate this Agreement effective May 1, 2003, or
any subsequent annual term thereafter.
- 11 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
GREELEY GAS COMPANY, A DIVISION OF
ATMOS ENERGY CORPORATION (Shipper)
AND
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
- -------------------------------------------------------------------------------
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
- -------------------------------------------------------------------------------
Chalk Bluffs 4,370 General
- -------------------------------------------------------------------------------
CIG Ft Lupton 87 General
- -------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Corsey Group 906412694 20 1st meter $185 same as 11/1/98 08/26/90 11/1/98 9/30/2003
Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
East 606412695 50 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
Keenesburg meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
Gilcrest 506412766 425 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
Hill-N-Park 206412697 360 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 12 -
<PAGE>
<TABLE>
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Hudson 406412700 375 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
Keenesburg 306412710 340 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
Nunn 206412739 175 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 13 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE
(cont'd.)
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Pierce 606412742 400 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- --------------------------------------------------------------------------------------------------------------------------
Roggen 706412751 70 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
South Gate 106412768 50 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
Trailer meter Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
South Roggen 106412773 15 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
West Hudson 306412705 300 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
meter Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
West 506412771 35 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
LaSalle meter Exh. A-1
Group
- -------------------------------------------------------------------------------------------------------------------------
Prospect 306412748 55 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003
Valley meter Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
Misc. Farm 1,700 same as 11/1/98 08/26/90 11/1/98 9/30/2003
Taps Exh. A-1
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 4,370 Dth
Rates for Firm Transportation Service:
- 14 -
<PAGE>
Unless otherwise specified as provided below, the Transportation Commodity
Charge for services hereunder for all quantities nominated by Shipper and
delivered by Company to the Delivery Points identified above shall be $.05/Dth
inclusive of any Demand Side Management Charges and General Rate Schedule
Adjustments, plus additional surcharges for reimbursement of applicable taxes,
franchise fees and Fuel Reimbursement. The parties further agree that the
percentage for Fuel Reimbursement to be retained by Company for deliveries made
to Front Range Delivery Points under the above referenced agreements shall be
2%.
- 15 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE
(cont'd.)
The Transportation Commodity Charge provided above shall continue in effect from
November 1, 1998 through April 30, 2003, unless a revised discounted or minimum
Transportation Commodity Charge applicable to service hereunder is ordered by
the Commission or the Commission issues an order in a rate proceeding which
specifically disallows the Company's proposed recovery in its jurisdictional
rates of the revenue requirement attributable to the difference between the
Transportation Commodity Charge provided above and the applicable Maximum
Transportation Commodity Charge set forth in Company's tariff, either through a
discount adjustment on transportation throughput or other method of rate
recovery. If a revised discounted or minimum Transportation Commodity Charge
applicable to service hereunder is ordered by the Commission or the Commission
issues an order in a rate proceeding disallowing the Company's proposed recovery
of the revenue requirement attributable to the discount provided hereunder, the
parties shall have 30 days after the date of such to attempt to adjust other
components of such total charge so that there will be no increase in such total
charge paid by Shipper hereunder. If the parties are unable to make any
adjustment within the then existing Commission orders and there is an increase
in such total charge paid by Shipper, Shipper shall pay the increased rate
required by the Commission but shall have the right to terminate this Agreement
at any time and, notwithstanding anything contained herein to the contrary,
without any termination or other charge, thereafter upon 30 days prior written
notice to Company.
Upon the expiration of the term of the discounted Transportation Commodity
Charge, as specified herein, the Transportation Commodity Charge shall
automatically revert to the full Standard Rate as applicable under Company's
then-effective Gas Transportation Tariff, as approved and on file with the
Commission. A minimum of ninety days prior to April 30, 2003, Shipper may
request a price redetermination for the discounted rate provided above. The
parties shall endeavor to reach a mutually agreeable rate prior to May 1, 2003
to be effective prospectively thereafter. If no such redetermined rate can be
agreed upon, either party may terminate this Agreement effective May 1, 2003, or
any subsequent annual term thereafter.
- 16 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "B-1" ELECTRONICALLY METERED SOUTHERN
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
GREELEY GAS COMPANY, A DIVISION OF
ATMOS ENERGY CORPORATION (Shipper)
AND
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
- --------------------------------------------------------------------------------
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
- --------------------------------------------------------------------------------
Outlet of Tiffany Compressor 6,500 Stabilized
Station
- --------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Crested 406412639 700 addt'l $125 TF 1yr. 11/28/90 11/1/98 4/30/99
Butte Town meter
Border
Station
- --------------------------------------------------------------------------------------------------------------------------
East 306412687 2,500 addt'l $125 TF 1yr. 05/06/87 11/1/98 4/30/99
Gunnison meter
Town
Border
Station
- --------------------------------------------------------------------------------------------------------------------------
Salida Town 206412701 2,600 addt'l $125 TF 1yr. 05/06/87 11/1/98 4/30/99
Border meter
Station
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 5,800 Dth
- 17 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "B-2" NON-ELECTRONICALLY METERED SOUTHERN
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
GREELEY GAS COMPANY, A DIVISION OF
ATMOS ENERGY CORPORATION (Shipper)
AND
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
- --------------------------------------------------------------------------------
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
- --------------------------------------------------------------------------------
Outlet of Tiffany Compressor 1,115 Stabilized
Station
- --------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Poncha 706412690 100 addt'l. $125 TF 1yr. 11/28/90 11/1/98 4/30/99
Springs meter
- ---------------------------------------------------------------------------------------------------------------------------
Chalk Creek 206412678 85 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99
meter
- ---------------------------------------------------------------------------------------------------------------------------
Tomichi 106412706 40 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99
Village meter
- ---------------------------------------------------------------------------------------------------------------------------
West 906412707 375 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99
Gunnison meter
Town
Border
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 18 -
<PAGE>
<TABLE>
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Misc. Farm 800 TF 1yr. 05/06/87 11/1/98 4/30/99
Taps
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 1,400 Dth
- 19 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "C-1" ELECTRONICALLY METERED WESTERN
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
GREELEY GAS COMPANY, A DIVISION OF
ATMOS ENERGY CORPORATION (Shipper)
AND
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
- -------------------------------------------------------------------------------
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
- -------------------------------------------------------------------------------
KNGWRD 680 General
- -------------------------------------------------------------------------------
MOFRRO 575 General
- -------------------------------------------------------------------------------
LONGCA 266 General
- -------------------------------------------------------------------------------
NF1GCA 1,770 General
- -------------------------------------------------------------------------------
NF1GHC 3,540 General
- -------------------------------------------------------------------------------
NF2GCA 3,540 General
- -------------------------------------------------------------------------------
ROSGCA 89 General
- -------------------------------------------------------------------------------
TERGCA 22 General
- -------------------------------------------------------------------------------
TWIGCA 66 General
- -------------------------------------------------------------------------------
CIG Ft Lupton General
- -------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Craig 206412744 4,648 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99
meter
- ---------------------------------------------------------------------------------------------------------------------------
Meeker 706413010 1,000 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99
meter
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 20 -
<PAGE>
<TABLE>
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Hayden TBS 506412747 2,600 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99
meter
- --------------------------------------------------------------------------------------------------------------------------
Mt. Werner 506412752 2,600 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99
#1 meter
- --------------------------------------------------------------------------------------------------------------------------
Steamboat 306412772 1,215 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99
TBS meter
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 10,163 Dth
- 21 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "C-2" NON-ELECTRONICALLY METERED WESTERN
TO THE FIRM TRANSPORTATION SERVICE AGREEMENT
BETWEEN
ATMOS ENERGY CORPORATION (Shipper)
AND
GREELEY GAS COMPANY, A DIVISION OF
PUBLIC SERVICE COMPANY OF COLORADO (Company)
1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
- --------------------------------------------------------------------------------
KNGWRD 88 General
- --------------------------------------------------------------------------------
MOFRRO 75 General
- --------------------------------------------------------------------------------
LONGCA 34 General
- --------------------------------------------------------------------------------
NF1GCA 230 General
- --------------------------------------------------------------------------------
NF1GHC 460 General
- --------------------------------------------------------------------------------
NF2GCA 460 General
- --------------------------------------------------------------------------------
ROSGCA 11 General
- --------------------------------------------------------------------------------
TERGCA 3 General
- --------------------------------------------------------------------------------
TWIGCA 9 General
- --------------------------------------------------------------------------------
CIG Ft Lupton General
- --------------------------------------------------------------------------------
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
<TABLE>
<CAPTION>
Firm Service Transport- Effective
Capacity and Specific ation Date Of Date Termination
Delivery Peak Day Facility Facility Commodity Term of First of of Service
Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date
(Dth)
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Thompson 406412762 45 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99
Hill meter
- ---------------------------------------------------------------------------------------------------------------------------
Milner 106412749 65 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99
Town Brder meter
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
- 22 -
<PAGE>
<TABLE>
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Steamboat 206412758 200 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99
II West meter
- ---------------------------------------------------------------------------------------------------------------------------
Brooklyn 606412737 627 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99
Group meter
- ---------------------------------------------------------------------------------------------------------------------------
Misc. Farm 1,233 TF 1yr. 10/20/86 11/1/98 4/30/99
Taps
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
Total Firm Capacity Reservation Peak Day Quantity: 2,170 Dth
- 23 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "D"
GAS UTILIZATION CURVES
Stabilized Utilization Curve
[Public Service Company of Colorado
Stabilized Utilization Curve Graph appears here]
The Utilization Curve is a general representation of the natural gas quality
which is acceptable from a utilization standpoint. However, the gas composition
must be known in order to determine if a supply is acceptable and can be
interchanged with supplies in a pipeline system. PSCo reserves the right in all
instances to evaluate gas composition to determine system compatibility and to
refuse any gas which is unacceptable from a utilization basis.
- 24 -
<PAGE>
Contract No.: 123535
Effective Date Of Agreement: 11/01/98
Effective Date of Exhibit: 11/01/98
EXHIBIT "E"
GAS UTILIZATION CURVES
General Utilization Curve
[Public Service Company of Colorado
Stabilized Utilization Curve Graph appears here]
The Utilization Curve is a general representation of the natural gas quality
which is acceptable from a utilization standpoint. However, the gas composition
must be known in order to determine if a supply is acceptable and can be
interchanged with supplies in a pipeline system. PSCo reserves the right in all
instances to evaluate gas composition to determine system compatibility and to
refuse any gas which is unacceptable from a utilization basis.
- 25 -
<PAGE>
Exhibit 10.10(d)
Firm Transportation Service Agreement
Contract No. 33181000A
Rate Schedule TF-1
between
Colorado Interstate Gas Company
and
Greeley Gas Company,
a division of Atmos Energy Corporation
Dated: July 1, 1998
<PAGE>
Page 2
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-1
The Parties identified below, in consideration of their mutual promises, agree
as follows:
1. Transporter: Colorado Interstate Gas Company
2. Shipper: Greeley Gas Company, a division of Atmos Energy Corporation
3. Applicable Tariff: Transporter's FERC Gas Tariff, First Revised Volume No.
1, as the same may be amended or superseded from time to time ("the Tariff").
4. Changes in Rates and Terms: Transporter shall have the right to propose to
the FERC changes in its rates and terms of service, and this Agreement shall be
deemed to include any changes which are made effective pursuant to FERC Order or
regulation or provisions of law, without prejudice to Shipper's right to protest
the same.
5. Transportation Service: Transportation Service at and between Primary
Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm basis.
Receipt and Delivery of quantities at Secondary Point(s) of Receipt and/or
Secondary Point(s) of Delivery shall be in accordance with the Tariff.
6. Points of Receipt and Delivery: Shipper agrees to Tender gas for
Transportation Service, and Transporter agrees to accept Receipt Quantities at
the Primary Point(s) of Receipt identified in Exhibit "A." Transporter agrees to
provide Transportation Service and Deliver gas to Shipper (or for Shipper's
account) at the Primary Point(s) of Delivery identified in Exhibit "A."
7. Rates and Surcharges: As set forth in Exhibit "B."
8. Negotiated Rate Agreement: N/A
9. Maximum Delivery Quantity ("MDQ"):
November through March - 0 Dth per Day
April, May, September, October - 1,836 Dth per Day
June through August - 3,979 Dth per Day
10. Term of Agreement: Beginning: July 1, 1998
Extending through: September 30, 2000
11. Notices, Statements, and Bills:
To Shipper:
Invoices for Transportation:
<PAGE>
Page 3
Greeley Gas Company,
a division of Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
Attention: Gas Supply Department
All Notices:
Greeley Gas Company,
a division of Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
Attention: John Hack
To Transporter:
See Payments, Notices, Nominations, and Points of Contact sheets in
the Tariff.
12. Supersedes and cancels prior Agreement: When this Agreement becomes
effective, it shall supersede and cancel the following agreement between the
Parties: The Firm Transportation Service Agreement between Transporter and
Shipper dated October 1, 1997, referred to as Transporter's Agreement No.
33181000.
13. Adjustment to Rate Schedule TF-1 and/or General Terms and Conditions: N/A
14. Incorporation by Reference: This Agreement in all respects shall be subject
to the provisions of Rate Schedule TF-1 and to the applicable provisions of the
General Terms and Conditions of the Tariff as filed with, and made effective by,
the FERC as same may change from time to time (and as they may be amended
pursuant to Section 13 of the Agreement).
IN WITNESS WHEREOF, the parties hereto have executed this Agreement.
Transporter: Shipper:
Colorado Interstate Gas Company Greeley Gas Company, a
division of Atmos Energy
Corporation
By By
------------------------- -------------------------
Thomas L. Price
Vice President
----------------------------
(Print or type name)
----------------------------
(Print or type title)
<PAGE>
Page 4
EXHIBIT "A"
Firm Transportation Service Agreement
between
Colorado Interstate Gas Company
and
Greeley Gas Company,
a division of Atmos Energy Corporation
Dated: July 1, 1998
1. Shipper's Maximum Delivery Quantity ("MDQ") for the following months
shall be as follows:
November - March 0 Dth per Day
April, May, September, October 1,836 Dth per Day
June - August 3,979 Dth per Day
<TABLE>
<CAPTION>
Primary Point(s) of
Receipt Quantity
(Dth per Day) (Note 2)
-------- ---------
Primary Point(s) of Receipt April, Maximum
of Receipt November May, June Receipt
(Note 1) through September through Pressure
March October August p.s.i.g.
- ------------------------- -------- --------- ------- --------
<S> <C> <C> <C> <C>
Central System
Lakin Master Meter 0 1,037 2,228 220
------ ------- -------
Southern System
Big Canyon 0 224 491 955(4)
Mocane 0 575 1,260 65
------ ------- -------
Total Southern System 0 799 1,751
------ ------- -------
TOTAL 0 1,836 3,979
------ ------- -------
</TABLE>
<PAGE>
Page 5
<TABLE>
<CAPTION>
Primary Point(s) of
Delivery Quantity
(Dth per Day) (Note 3)
-------- ----------
April, Maximum
November May, June Delivery
Primary Point(s) of Delivery through September, through Pressure
(Note 1) March October August p.s.i.g.
- ------------------------- -------- ---------- ------- ----------
<S> <C> <C> <C> <C>
Canon City Group (Note 5)
Canon City 0 1,269 2,750 (Note 6)
Colorado State Penitentiary 0 89 194 100
Engineering Station 476+78 0 1 3 Line Pressure
Florence City Gate 0 297 643 60
Fremont County Industrial Park 0 3 6 Line Pressure
Penrose City Gate 0 40 88 60
Penrose PBS-2 0 39 84 Line Pressure
Portland City Gate 0 10 23 100
Pritchett City Gate 0 10 23 150
------ ------- -----
Total Canon City Group 0 1,758 3,814
------ ------- -----
Total Capacity Release 0 1,445 3,130
------ ------- -----
Eads Group
Brandon Station 8 18 350
Eads City Gate 0 62 135 60
Highline Taps:
Neoplan (Bent County) 0 1 2 Line Pressure
Penrose South (Fremont County) 0 3 7 Line Pressure
L.J. Stafford (Baca County) 0 1 3 Line Pressure
------ ------- -----
Total Eads Group 0 76 167
------ ------- -----
McClave Delivery 0 105 227 500
------ ------- -----
Springfield 0 210 455 Line Pressure
------ ------- -----
TOTAL 0 1,836 3,979
------ ------- -----
Storage Injection 0 799 1,100 N/A
</TABLE>
<PAGE>
Page 6
NOTES:
(1) Information regarding Point(s) of Receipt and Point(s) of Delivery,
including legal descriptions, measuring parties, and interconnecting parties,
shall be posted on Transporter's electronic bulletin board. Transporter shall
update such information from time to time to include additions, deletions, or
any other revisions deemed appropriate by Transporter.
(2) Each Point of Receipt Quantity may be increased by an amount equal to
Transporter's Fuel Reimbursement percentage. Shipper shall be responsible for
providing such Fuel Reimbursement at each Point of Receipt on a pro rata basis
based on the quantities received on any Day at a Point of Receipt divided by the
total quantity Delivered at all Point(s) of Delivery under this Transportation
Service Agreement.
(3) The sum of the Delivery Quantities at Point(s) of Delivery shall be equal
to or less than Shipper's MDQ.
(4) Minimum pressure Shipper will deliver gas to Transporter is 350 p.s.i.g.
(5) For Capacity Release purposes, the aggregate of the Canon City Group Point
of Delivery Quantities is as designated (e.g., 1,445 Dth per Day April, May,
September, October). To the extent that Shipper is not utilizing a portion of
its remaining Point of Delivery Quantities at non-Canon City Group Points of
Delivery, Shipper may nominate up to the Canon City Group total (e.g., 1,758 Dth
per Day April, May, September, October), provided that volumes Tendered by
Shipper under this Agreement do not exceed the monthly MDQ (e.g., 1,836 Dth per
Day April, May, September, October) unless an Authorized Overrun has been
granted to Shipper by Transporter.
(6) Line pressure but not less than 100 p.s.i.g.
<PAGE>
Page 7
EXHIBIT "B"
Firm Transportation Service Agreement
between
Colorado Interstate Gas Company
and
Greeley Gas Company,
a division of Atmos Energy Corporation
Dated: July 1, 1998
<TABLE>
<CAPTION>
Primary Primary R1
Point(s) Points of Reservation Commodity Term of Fuel
of Receipt Delivery Rate Rate Rate Reimbursement Surcharges
- ---------- ----------- ----------- --------- ------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
As listed As listed on $1.46 (Notes 1 Through (Note 2) (Note 3)
on Exhibit on Exhibit and 4) 9/30/00
"A" "A"
<CAPTION>
Secondary
Point(s) Primary R1
of Point(s) of Reservation Commodity Term of Fuel
Receipt Delivery Rate Rate Rate Reimbursement Surcharges
- ---------- ----------- ----------- --------- ------- ------------- ----------
All As listed on $1.46 (Notes 1 Through (Note 2) (Note 3)
Exhibit "A" and 4) 9/30/00
<CAPTION>
Secondary Secondary R1
Point(s) Point(s) of Reservation Commodity Term Fuel
of Receipt Delivery Rate Rate of Rate Reimbursement Surcharges
- ---------- ----------- ----------- --------- ------- ------------- ----------
All All (Note 1) (Note 1) Through (Note 2) (Note 3)
9/30/00
</TABLE>
<PAGE>
Page 8
EXHIBIT "B"
NOTES:
(1) Unless otherwise agreed by the Parties in writing, the rates for service
hereunder shall be Transporter's maximum rates for service under Rate Schedule
TF-1 or other superseding Rate Schedules, as such rates may be changed from time
to time.
(2) Fuel Reimbursement shall be as stated on Transporter's Schedule of
Surcharges and Fees in the Tariff, as they may be changed from time to time,
unless otherwise agreed between the Parties.
(3) Surcharges, If Applicable:
All applicable surcharges, unless otherwise specified, shall be the maximum
surcharge rate as stated in the Schedule of Surcharges and Fees in The Tariff,
as such surcharges may be changed from time to time.
GQC:
The Gas Quality Control Surcharge shall be assessed pursuant to Article 20 of
the General Terms and Conditions as set forth in The Tariff.
GRI:
The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms
and Conditions as set forth in The Tariff.
HFS:
The Hourly Flexibility Surcharge shall be assessed pursuant to Article 20 of the
General Terms and Conditions as set forth in The Tariff.
Order No. 636 Transition Cost Mechanism:
Surcharge(s) shall be assessed pursuant to Article 21 of the General Terms and
Conditions as set forth in The Tariff.
ACA:
The ACA Surcharge shall be assessed pursuant to Article 19 of the General Terms
and Conditions as set forth in The Tariff.
(4) The Authorized Overrun Rate charged by Transporter shall be determined
pursuant to the Stipulation and Agreement in Docket No. RP96-190, when
applicable, while such Settlement is in effect.
<PAGE>
Exhibit 10.30(d)
AMENDMENT NO. 3 TO
CONSULTING AGREEMENT
THIS AMENDMENT NO. 3 TO CONSULTING AGREEMENT (the "Amendment") is made and
entered into this 10th day of November, 1999, by and between ATMOS ENERGY
CORPORATION, a Texas and Virginia corporation (the "Company"), and CHARLES K.
VAUGHAN ("Consultant").
WHEREAS, the Company and Consultant entered into that certain Consulting
Agreement dated October 1, 1994, as amended by Amendment No. 1 to Consulting
Agreement dated May 14, 1997 and Amendment No. 2 to Consulting Agreement dated
August 12, 1998 (the "Agreement"); and
WHEREAS, the Company and Consultant desire to amend the Agreement as set
forth below and to extend the term thereof for an additional one-year period;
NOW THEREFORE, for and in consideration of the premises and other good and
valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereby agree as follows:
1. Paragraph 5 of the Agreement shall be deleted and replaced in its
entirety by the following:
5.1. Change in Control. Upon a "Change in Control" of the Company, all
sums payable to Consultant over the course of the term of this Agreement
shall instead be paid by Company to Consultant within ten days of a "Change
in Control". A "Change in Control" of the Company shall be deemed to have
occurred if:
(a) Any "Person" (as defined in Section 5.2(a) below), other than (1)
the Company or any of its subsidiaries, (2) a trustee or other fiduciary
holding securities under an employee benefit plan of the Company or any of
its Affiliates, (3) an underwriter temporarily holding securities pursuant
to an offering of such securities, or (4) a corporation owned, directly or
indirectly, by the shareholders of the Company in substantially the same
proportions as their ownership of stock of the Company, is or becomes the
"beneficial owner" (as defined in Section 5.2(b)
<PAGE>
below), directly or indirectly, of securities of the Company (not including
in the securities beneficially owned by such person any securities acquired
directly from the Company or its Affiliates) representing 33 1/3% or more
of the combined voting power of the Company's then outstanding securities,
or 33 1/3% or more of the then outstanding common stock of the Company,
excluding any Person who becomes such a beneficial owner in connection with
a transaction described in subparagraph (c)(1) below.
(b) During any period of two consecutive years (the "Period"),
individuals who at the beginning of the Period constitute the Board of
Directors of the Company and any "new director" (as defined in Section
5.2(c) below) cease for any reason to constitute a majority of the Board of
Directors.
(c) There is consummated a merger or consolidation of the Company or
any direct or indirect subsidiary of the Company with any other
corporation, except if:
(1) the merger or consolidation would result in the voting
securities of the Company outstanding immediately prior thereto
continuing to represent (either by remaining outstanding or by being
converted into voting securities of the surviving entity or any
parent thereof) at least sixty percent (60%) of the combined voting
power of the voting securities of the Company or such surviving
entity or any parent thereof outstanding immediately after such
merger or consolidation; or
(2) the merger or consolidation is effected to implement a
recapitalization of the Company (or similar transaction) in which no
Person is or becomes the beneficial owner, directly or indirectly, of
securities of the Company (not including in the securities
beneficially owned by such Person any securities acquired directly
from the Company or its Affiliates other than in connection with the
acquisition by the Company or its Affiliates of a business)
<PAGE>
representing 60% or more of the combined voting power of the
Company's then outstanding securities;
(d) The shareholders of the Company approve a plan of complete
liquidation or dissolution of the Company or an agreement for the sale or
disposition by the Company of all or substantially all the Company's
assets, other than a sale or disposition by the Company of all or
substantially all of the Company's assets to an entity, at least 60% of the
combined voting power of the voting securities of which are owned by the
stockholders of the Company in substantially the same proportions as their
ownership of the Company immediately prior to such sale.
5.2. Definitions. For purposes of Section 5.1 above,
(a) "Person" shall have the meaning given in Section 3(a)(9) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act") as
modified and used in Sections 13(d) and 14(d) of the Exchange Act.
(b) "Beneficial owner" shall have the meaning provided in Rule 13d-3
under the Exchange Act.
(c) "New director" shall mean an individual whose election by the
Company's Board of Directors or nomination for election by the Company's
shareholders was approved by a vote of at least two-thirds (2/3) of the
directors then still in office who either were directors at the beginning
of the Period or whose election or nomination for election was previously
so approved or recommended. However, "new director" shall not include a
director whose initial assumption of office is in connection with an actual
or threatened election contest, including but not limited to a consent
solicitation relating to the election of directors of the Company.
(d) "Affiliate" shall have the meaning set forth in Rule 12b-2
promulgated under Section 12 of the Exchange Act.
2. Extension of Term. In accordance with Subparagraph 4(a) of the
Agreement, the Company and the Consultant hereby agree to extend the term of the
Agreement for an additional one-
<PAGE>
year period commencing on October 1, 2000 and ending September 30, 2001. The
Consultant's annual compensation during such year shall be $130,000 to be paid
in equal semi-annual installments on October 1, 2000 and April 1, 2001.
3. No Other Amendment. Except as expressly amended hereby, all of the other
terms, provisions, and conditions of the Agreement are hereby ratified and
confirmed and shall remain unchanged and in full force and effect. To the extent
any terms or provisions of this Amendment conflict with those of the Agreement,
the terms and provisions of the Agreement shall control. This Amendment shall be
deemed a part of, and is hereby incorporated into the Agreement. The Agreement
and any and all other documents heretofore, now, or hereafter executed and
delivered pursuant to the terms of the Agreement are hereby amended so that any
reference to the Agreement shall mean a reference to the Agreement as amended
hereby.
4. Governing Law. This Amendment shall be governed by, and construed in
accordance with, the laws of the State of Texas.
5. Counterparts. This Amendment may be executed in counterparts, each of
which will be an original, but all of which together will constitute one and the
same agreement.
IN WITNESS WHEREOF, the parties hereto have executed this Amendment
effective as of the date and year first above written.
COMPANY
ATMOS ENERGY CORPORATION
By: /s/ ROBERT W. BEST
---------------------------------
Robert W. Best
Chairman, President and
Chief Executive Officer
CONSULTANT
/s/ CHARLES K. VAUGHAN
-------------------------------------
CHARLES K. VAUGHAN
<PAGE>
EXHIBIT 13
----------
ATMOS ENERGY CORPORATION
1999 ANNUAL REPORT
FINANCIAL REVIEW
Page no.
Selected financial data 2
Market price of common stock and related matters 3
Management's discussion and analysis of
financial condition and results of operations 4
Management's responsibility for financial statements 33
Report of independent auditors 34
Consolidated balance sheets 35
Consolidated statements of income 37
Consolidated statements of shareholders' equity 38
Consolidated statements of cash flows 40
Notes to consolidated financial statements 42
1
<PAGE>
SELECTED FINANCIAL DATA
The following table sets forth selected financial data of the Company and
should be read in conjunction with the consolidated financial statements
included herein.
Year ended September 30,
--------------------------------------------------------
1999 1998 1997 1996 1995
========== ========== ========== ========== ========
(In thousands, except per share data)
Operating
revenues $ 690,196 $ 848,208 $ 906,835 $ 886,691 $749,555
========== ========== ========== ========== ========
Net income $ 17,744 $ 55,265 $ 23,838 $ 41,151 $ 28,808
========== ========== ========== ========== ========
Diluted net income
per share $ .58 $ 1.84 $ .81 $ 1.42 $ 1.06
========== ========== ========== ========== ========
Cash dividends
per share $ 1.10 $ 1.06 $ 1.01 $ .98 $ .96
========== ========== ========== ========== ========
Total assets at
end of year $1,230,537 $1,141,390 $1,088,311 $1,010,610 $900,948
========== ========== ========== ========== ========
Long-term debt at
end of year $ 377,483 $ 398,548 $ 302,981 $ 276,162 $294,463
========== ========== ========== ========== ========
2
<PAGE>
MARKET PRICE OF COMMON STOCK AND RELATED MATTERS
The Company's stock trades on the New York Stock Exchange under the trading
symbol "ATO". The high and low sale prices and dividends paid per share of the
Company's common stock for fiscal 1999 and 1998 are listed below. The high and
low prices listed are the actual closing NYSE quotes for Atmos shares.
Fiscal year 1999
---------------------------------------
Dividends
High Low paid
Quarter ended: --------- --------- ---------
December 31 $32 1/4 $28 3/8 $.275
March 31 32 11/16 23 1/16 .275
June 30 26 5/16 24 .275
September 30 26 3/8 23 7/8 .275
-----
$1.10
=====
Fiscal year 1998
---------------------------------------
Dividends
High Low paid
Quarter ended: --------- --------- ---------
December 31 $30 7/16 $24 5/8 $.265
March 31 30 5/16 26 5/16 .265
June 30 31 1/16 28 13/16 .265
September 30 30 7/8 25 3/4 .265
-----
$1.06
=====
See Note 4 of notes to consolidated financial statements for restriction on
payment of dividends. The number of record holders of the Company's common stock
on September 30, 1999 was 35,179.
3
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Introduction
This section provides management's discussion of Atmos Energy Corporation's
(the "Company" or "Atmos") financial condition, cash flows and results of
operations with specific information on liquidity, capital resources and results
of operations. It includes management's interpretation of such financial
results, the factors affecting these results, the major factors expected to
affect future operating results, and future investment and financing plans. This
discussion should be read in conjunction with the Company's consolidated
financial statements and notes thereto.
Cautionary Statement for the Purposes of the Safe Harbor under the Private
Securities Litigation Reform Act of 1995
The matters discussed or incorporated by reference in this Annual Report
may contain "forward-looking statements" within the meaning of Section 21E of
the Securities Exchange Act of 1934. All statements other than statements of
historical facts included in this "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the notes to consolidated
financial statements, regarding the Company's financial position, business
strategy and plans and objectives of management of the Company for future
operations, are forward-looking statements made in good faith by the Company and
are intended to qualify for the safe harbor from liability established by the
Private Securities Litigation Reform Act of 1995. When used in this Report or in
any of the Company's other documents or oral presentations, the words
"anticipate," "expect," "estimate," "plans," "believes," "objective,"
"forecast," "goal" or similar words are intended to identify forward-looking
statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those
expressed or implied in the statements relating to the Company's operations,
markets, services, rates, recovery of costs, availability of gas supply, and
other factors. These risks and uncertainties include, but are not limited to,
national, regional and local economic and competitive conditions, regulatory and
business trends and decisions, technological developments, Year 2000 issues,
inflation rates, weather conditions, and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the Company.
4
<PAGE>
Accordingly, while the Company believes that the expectations reflected in
the forward-looking statements are reasonable, there can be no assurance that
such expectations will be realized or will approximate actual results.
Year 2000 Readiness
The Year 2000 issues arose because many computer systems and software
applications, as well as embedded computer chips in plant and equipment
currently in use, were constructed using an abbreviated date field that
eliminates the first two digits of the year. On January 1, 2000, these systems,
applications and embedded computer chips may incorrectly recognize the date as
January 1, 1900. Accordingly, many computer systems and software applications,
as well as embedded chips, may incorrectly process financial and operating
information or fail to process such information completely. The Company has been
aware of these issues and has continued to address their potential effects on
its computer systems, software applications and plant and equipment.
State of readiness. In October 1996, the Company established its Year 2000
Project Team with the mission of ensuring that all critical systems, facilities
and processes are identified, analyzed for Year 2000 readiness, corrected if
necessary, and tested if changes are necessary. The Year 2000 Project Team is
headed by an officer of the Company and consists of representatives from all
business units and shared services units of the Company. The Company has a Year
2000 strategy in place and has continued to implement its Year 2000 plan to
manage and minimize risks associated with the Year 2000 issues.
The Company also received comprehensive assessments in April and July 1999,
updating an earlier assessment completed in June 1998, by an independent
consulting firm, which specializes in such matters, of the risks posed for the
Company and its business units by the Year 2000 issues, including assessments of
the risks in each area of the Company involving the use of computer technology
and assessments of the business and legal risks created for the Company by the
Year 2000 issues. Such assessments also addressed the risks associated with the
Company's embedded technologies such as micro-controllers or microchips embedded
in non-information technology-related equipment.
With respect to information technology ("IT") systems, the Company has
conducted an inventory and review of its application software on all platforms
including the mainframe, H-P Unix, local area network and personal computers and
has remediated
5
<PAGE>
Year 2000 issues relating to such operating environments. Concerning non-IT
systems, including embedded technology, the Company has conducted an inventory
and review of all of its telecommunications, security access and building
control systems, forms, reports and other business processes and activities as
well as the equipment and facilities utilized in the Company's gas distribution
and storage systems and has remediated all Year 2000 issues identified.
The Company's Year 2000 plan includes specific timetables for the following
categories of tasks for each of its shared services units and business units
with respect to both IT systems and embedded technology as follows:
- Identification of Year 2000 issues--completed;
- Prioritization of Year 2000 issues--completed;
- Estimation of total Year 2000-related costs--completed;
- Implementation of Year 2000 solutions--completed;
- Testing of Year 2000 solutions--completed;
- Certification of Year 2000 readiness by third party vendors and suppliers--
completed;
- Monitoring of all systems for changes in current systems that would require
changes in Year 2000 plan--completed;
- Development of Year 2000 contingency plans--completed;
- Final Year 2000 tests--began October 1, 1999, and ongoing, including the
Clean Management Program.
The Company has also conducted an inventory and review of mission critical
computer systems provided by outside vendors and has contacted all major vendors
to coordinate their Year 2000 readiness schedules with those of the Company.
The Company has required vendors who provide mission critical goods or services
to submit to the Company their readiness plans and to certify readiness in order
to continue to do business with the Company. As discussed above, the Company
has also tested vendor products that provide mission critical goods or services
to ensure their Year 2000 readiness. In addition, the Company has identified
its key suppliers, including gas suppliers and gas pipelines, and has
communicated with them, including conducting on-site visits, for the purpose of
evaluating the status of their solutions to their respective Year 2000 issues.
Costs to Address Year 2000 issues. As of September 30, 1999, the Company
had incurred a total of over $900,000 in direct fees and expenses in connection
with its Year 2000 efforts. The Company expects to spend approximately $1.0
million in direct fees and expenses on its Year 2000 efforts by December 31,
1999. In addition, as part of its normal systems
6
<PAGE>
upgrade in the ordinary course of business, the Company has replaced its
customer information system, accounting and financial reporting system, and
human resources system. Although these systems are Year 2000 ready, the
replacement of these systems was not accelerated to 1999 solely in an attempt to
address Year 2000 issues.
Risks of Year 2000 issues and contingency plans. As required by the United
States Securities and Exchange Commission ("SEC"), the Company has identified
what it believes are its "most reasonably likely worst case Year 2000
scenarios." These scenarios are (i) the temporary interference with the
Company's ability to receive gas from upstream suppliers and deliver gas to
customers; (ii) the temporary interference with the Company's ability to
communicate with customers regarding any problems with service they may
encounter; and (iii) the temporary inability to send invoices to and receive
payments from customers.
The "most reasonably likely worst case scenario" associated with the Year
2000 issues would be the Company's temporary inability to continue to transport
and distribute gas to its customers without interruption. In the event the
Company and/or its suppliers and vendors were unable to remediate critical Year
2000 issues prior to January 1, 2000, the ability of the Company to deliver gas
to its customers without interruption could be impacted. In order to address
this scenario, the Company has developed contingency plans to continue to
deliver gas primarily through manual intervention and other procedures should it
become necessary to do so. Such procedures include back-up power supply for its
critical distribution and storage operations, manual operation of the Company's
gas distribution and storage systems, and, if necessary, curtailment of supply.
The Company's storage capacity would be used to supplement system supply in the
event its suppliers or gas pipelines are unable to make deliveries.
With respect to communications with customers, which is heavily reliant on
services provided by third parties, the Company has evaluated Year 2000
readiness by such third parties and has continued to refine its contingency
plans to address any worst case scenarios. Concerning the billing and payment
systems, as previously discussed, the Company has replaced its customer
information system, accounting and financial reporting system, and human
resources system with systems that are Year 2000 ready, which should
substantially diminish the risk of Year 2000 issues. Nevertheless, the Company
has developed contingency plans and has continued to refine such plans in case
the billing and payment systems prove not to be Year 2000 ready.
7
<PAGE>
Despite the Company's efforts, there can be no assurance that all material
risks associated with Year 2000 issues relating to systems and embedded
technology within its control will have been adequately identified and corrected
before the end of 1999. However, as the result of its Year 2000 plan and the
replacement of the customer information system, accounting and financial
reporting system, and human resources system in 1999, the Company does not
believe that in the aggregate, Year 2000 issues with respect to both its own IT
and non-IT systems will be material to its business, operations or financial
condition. On the other hand, while the Company has researched the Year 2000
readiness of its suppliers and vendors, the Company can make no representations
regarding the Year 2000 readiness status of systems or parties outside its
control, and cannot assess the effect on it of any non-readiness by such systems
or parties.
Ratemaking procedures
The Company's five utility divisions are regulated by various state or
local public utility authorities. The method of determining regulated rates
varies among the 12 states in which the Company has utility operations. It is
the responsibility of the regulators to determine that utilities under their
jurisdiction operate in the best interests of customers while providing the
utilities the opportunity to earn a reasonable return on investment.
In a general rate case, the applicable regulatory authority, which is
typically the state public utility commission, establishes a base margin, which
is the amount of revenue authorized to be collected from customers to recover
authorized operating expense (other than the cost of gas), depreciation,
interest, taxes and return on rate base. The Company's utility divisions
perform annual deficiency studies for each rate jurisdiction to determine when
to file rate cases, which are typically filed every two to five years.
Substantially all of the sales rates charged by the Company to its
customers fluctuate with the cost of gas purchased by the Company. Rates
established by regulatory authorities are adjusted for increases and decreases
in the Company's purchased gas cost through automatic purchased gas adjustment
mechanisms. Therefore, while the Company's operating revenues may fluctuate,
gross profit (which is defined as operating revenues less purchased gas cost) is
generally not eroded or enhanced because of gas cost increases or decreases.
8
<PAGE>
The overall reduction in net revenue from 1998 to 1999, other than the
reduction resulting from the effects of warmer than normal weather, confirms the
need for revised rates in certain jurisdictions. This is generally the result
of depreciation, operating expenses and interest expense associated with assets
placed in service but for which new rates have not been placed in effect to
allow the Company to recover the costs associated with those assets and to
provide a reasonable return on the investments made. In the regulatory
environment, assets have to be placed in service and historical test periods
established before rate cases can be filed. Once filed, regulatory bodies can
suspend implementation of the new rates while studying the cases. All the while,
as was the case for Atmos in 1999, the Company suffers the negative financial
effects of having placed assets in service without the benefit of rate relief.
In that regard, the Company engaged in three rate proceedings in 1999: a rate
investigation in Trans Louisiana Gas Company ("Trans La Division") before the
Louisiana Public Service Commission ("Louisiana Commission"); a rate case before
the Kentucky Public Service Commission ("Kentucky Commission") in Western
Kentucky Gas Company ("Western Kentucky Division"); and, two rate cases before
the cities in Energas Company ("Energas Division").
In August 1998, the Trans La Division filed with the Louisiana Commission
requesting a commodity performance mechanism and a rate freeze and the Louisiana
Commission responded by ordering a rate investigation. During the rate
proceeding, the Trans La Division sought to:
- Preserve revenues;
- Maintain competitive rates and create a use-based billing method for the
cost of service; and
- Restructure rates to be revenue neutral and reduce weather sensitivity.
In October 1999, a settlement was reached and the Louisiana Commission
issued an order, effective November 1, 1999, addressing each of these issues as
described in Note 3 of notes to the accompanying consolidated financial
statements.
In May 1999, the Western Kentucky Division requested an increase in
revenues of approximately $14.1 million from the Kentucky Public Service
Commission. In this case the Western Kentucky Division sought:
- To support the Company's business plans with regulatory strategy;
9
<PAGE>
- To apply marketing principles to develop rate proposals maximizing customer
satisfaction and profitability;
- To eliminate revenue deficiency resulting from investments since the last
rate case;
- To use Year 2000 projected costs to design future rates;
- To set rates to recover cost of each service; and
- To consistently earn authorized returns via long-term price stability
proposals, such as weather normalization adjustment and industrial rate
proposals designed to protect industrial margin losses resulting from
potential bypass.
The hearing is scheduled to begin in December 1999, and the final order is
required by statute by April 24, 2000.
In August 1999, the Energas Division filed rate cases with the cities
served by its West Texas System and the City of Amarillo. The Company is
seeking to:
- Eliminate revenue deficiency resulting from investments since the last rate
case;
- Develop funding mechanisms for projects which maintain safety and
reliability of the system;
- Differentiate customer rates and classes by true cost of service;
- Earn authorized return on equity in all Energas rate divisions;
- Eliminate or reduce the number of future rate filings;
- Prepare Energas for unbundling;
- Design rates that provide stable income regardless of weather; and
- Implement depreciation rates that reflect the actual retirements and
replacements.
The City of Amarillo is required by statute to reach a decision on the case
by the end of December 1999. The West Texas Cities must reach a decision by the
end of January 2000. If a settlement is not reached in either case at the
cities' level, the case will be appealed to the Railroad Commission of Texas.
The Company's rate activity for the last three fiscal years can be
summarized as follows: no rate changes in 1999, rate reductions of $1.8 million
in 1998, and rate increases of $9.4 million in 1997. For further information
regarding rate activity, see Note 3, "Rates," in notes to consolidated financial
statements.
10
<PAGE>
Weather and seasonality
The Company's natural gas and propane distribution businesses and
irrigation sales business are seasonal and dependent upon weather conditions in
the Company's service areas. Natural gas sales to residential, commercial, and
public authority customers and propane sales are affected by winter heating
season requirements. Sales to industrial customers are much less weather
sensitive. Sales to agricultural customers, who typically use natural gas to
power irrigation pumps during the period from March through September, are
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 effect
of significantly warmer than normal winter weather in 1999 on the Company's
consolidated volumes delivered is illustrated by the following degree day
information.
Year ended September 30,
-------------------------
1999 1998 1997
----- ----- -----
Sales volumes - Bcf 140.1 159.4 164.2
Transportation volumes - Bcf 55.5 56.2 48.8
----- ----- -----
Total 195.6 215.6 213.0
===== ===== =====
Degree days:
Actual 3,374 3,799 3,909
% of normal 85% 95% 98%
The effects of weather that is above or below normal are offset in the
Tennessee and Georgia jurisdictions served by the United Cities Gas Company
("United Cities Division") through Weather Normalization Adjustments ("WNA").
The Georgia Public Service Commission and the Tennessee Regulatory Authority
have approved WNAs. The WNA, effective October through May each year in
Georgia, and November through April each year in Tennessee, allow the United
Cities Division to increase the base rate portion of customers' bills when
weather is warmer than normal and decrease the base rate when weather is colder
than normal. The net effect of the WNA was an increase in revenues of $4.4
million, $.7 million and $2.6 million in 1999, 1998 and 1997, respectively.
Approximately 186,000 or 18% of the Company's meters in service are located in
Georgia and Tennessee.
11
<PAGE>
The Company recognizes the benefits of mitigating the effects of weather
where possible. In that regard, the Company is currently seeking a WNA in its
rate case in Kentucky and is seeking to increase its customer charge in Texas to
help offset some of the negative effects of weather. However, the Company
cannot predict whether it will receive the WNA in Kentucky or the increased
customer charges in Texas, or how much benefit might be achieved.
For further information regarding the impact of weather and seasonality on
operating results, see Note 17, "Selected Quarterly Financial Data (unaudited)"
in notes to consolidated financial statements herein.
CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of Cash Flows")
Fiscal 1999, like fiscal 1998, was a year in which total cash outflows
exceeded total cash inflows. This was generally the result of the combination
of lower than normal cash flows from operating activities as a result of warmer
than normal weather, higher than normal capital expenditures and mandatory long-
term debt retirement. This cash shortfall was financed with short-term debt and
sales of common stock through the Company's Employee Stock Ownership Plan
("ESOP") and its Direct Stock Purchase Plan ("DSPP").
Cash flows from operating activities
Cash flows from operating activities as reported in the consolidated
statement of cash flows totaled $84.7 million for 1999 compared with $91.7
million for 1998 and $68.7 million for 1997. The decrease in net cash provided
by operating activities from 1998 to 1999 was the result of lower net income in
1999 primarily due to lower sales volumes because of 11% warmer winter weather,
more rainfall in its agricultural service area and increased operating expenses.
The increase in net cash provided by operating activities from 1997 to 1998 was
the result of including a full 12 months of activity for the United Cities
Division in the 1998 statement of cash flows for the combined companies. Using
1997 beginning balances for United Cities Gas Company ("UCGC") as of December
31, 1996 resulted in large swings in certain seasonal asset and liability
accounts like accounts receivable and accounts payable. The changes in deferred
charges and other assets and other current liabilities in 1997 and 1998 were
related to merger and integration costs accrued and the related regulatory
assets recorded in the fourth quarter of 1997. The $35.7 million increase in
accounts receivable in 1999 was due to a change in over/under recovered
12
<PAGE>
gas costs from a credit(over-recovered) balance of $16.2 million at September
30, 1998 to a debit(under-recovered) balance of $7.6 at September 30, 1999, and
a temporary suspension in service cutoffs and normal efforts to collect past due
receivables in connection with the Company's conversion to the new customer
information and billing system. The over-recovered balance from 1998 was
returned to customers through reductions in their 1999 bills. The $12.0 million
increase in deferred charges and other assets net of non-cash amounts in 1999
was primarily due to increased pension assets. The $19.4 million increase in
accounts payable in 1999 was primarily due to increased gas costs payable. The
$11.9 million decrease in taxes payable in 1999 resulted from approximately 70%
lower income tax expense due to lower pretax income. See "Consolidated
Statements of Cash Flows" for other changes in assets and liabilities.
Cash flows from investing activities
A substantial portion of the Company's cash resources is used to fund its
ongoing construction program in order to provide natural gas services to a
growing customer base. Net cash used in investing activities totaled $109.6
million in 1999 compared with $118.8 million in 1998 and $121.1 million in 1997.
In 1998, the Company received $16.0 million from the sale of office buildings
and an airplane. Capital expenditures in fiscal 1999 amounted to $110.4
million, compared with $135.0 million in 1998 and $122.3 million in 1997.
Currently budgeted capital expenditures for fiscal 2000 total approximately $75
million and include funds for additional mains, services, meters, and equipment.
Completion of technology infrastructure and business process changes,
implementation of Oracle enterprise resource planning system, and Year 2000
readiness in 1999 allowed the Company to significantly reduce its planned
capital expenditures for fiscal 2000. Capital expenditures for fiscal 2000 are
planned to be financed from internally generated funds and financing activities,
as discussed below.
The excess of cash outflows over inflows has resulted in an increase in
debt as a percentage of total capitalization, including short-term debt, except
for the portion related to current storage gas, as shown in the table below.
13
<PAGE>
September 30,
------------------------------------------
1999 1998
---------------- -----------------
(In thousands)
Working capital
Short-term debt(1) $ 44,653 $ 48,909
======== ========
Short-term debt $123,651 13.8% $ 17,491 2.1%
Long-term debt 395,331 44.1% 456,331 54.0%
Shareholders' equity 377,663 42.1% 371,158 43.9%
-------- ----- -------- -----
Total capitalization $896,645 100.0% $844,980 100.0%
======== ===== ======== =====
(1)Includes short-term borrowings associated with working gas inventories.
The debt as a percentage of total capitalization was 57.9% and 56.1% at
September 30, 1999 and 1998, respectively. The Company's longer term plans are
to decrease the debt to capitalization ratio to nearer its target range of 50-
52% through cash flow generated from operations, continued issuance of new
common stock under its DSPP and ESOP, and reduction of capital expenditures to
the range of $75.0 million to $80.0 million from the range of $110.4 million to
$135.0 million in 1999 and 1998.
Cash flows from financing activities
Net cash provided by financing activities totaled $28.7 million for 1999
compared with $25.9 million for 1998 and $47.3 million for 1997. Financing
activities during these periods included issuance of common stock, dividend
payments, short-term borrowings from banks under the Company's credit lines, and
issuance and repayment of long-term debt.
Cash dividends paid. The Company paid $33.9 million in cash dividends
during 1999 compared with $31.8 million in 1998 and $26.4 million in 1997
(excluding dividends of $3.4 million paid by UCGC in the quarter ended December
31, 1996). Atmos raised the dividend rate a total of $.04 per share for both
1998 and 1999.
Short-term financing activities. At September 30, 1999, the Company had
committed lines of credit for $250.0 million and $12.0 million to provide for
short-term cash requirements. These credit facilities are negotiated at least
annually. At
14
<PAGE>
September 30, 1999, the Company also had uncommitted short-term credit lines of
$74.0 million, of which $70.4 million was unused. In October 1998, the Company
began a commercial paper program under which it is authorized to issue up to
$250.0 million. The commercial paper program is supported by a $250.0 million
committed line of credit. At September 30, 1999, the Company had $152.7 million
of commercial paper outstanding. During 1999, short-term debt increased $101.9
million due largely to lower net income and cash requirements of $61.0 million
for repayments of long-term debt and capital expenditures of $110.4 million.
Short-term debt decreased $100.9 million in 1998, due to the application of a
portion of the $150.0 million proceeds from the issuance of 6.75% debentures.
Short-term debt increased $38.8 million during 1997.
Long-term financing activities. No long-term debt was issued in fiscal
1999. In July 1998, the Company issued $150.0 million of 30-year 6.75%
debentures. The debentures are rated A3 by Moody's and A- by Standard & Poor's.
Long-term debt payments totaled $61.0 million, $16.3 million, and $14.7 million
for the years ended September 30, 1999, 1998 and 1997, respectively. The amount
for 1997 excludes repayments of $1.4 million by UCGC in the quarter ended
December 31, 1996. Payments of long-term debt in 1999, 1998 and 1997 consisted
of annual installments under the various loan documents.
The loan agreements pursuant to which the Company's Senior Notes and First
Mortgage Bonds 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. See Note 4 of the accompanying notes
to consolidated financial statements for more information on these covenants.
See Note 6 "Contingencies" for information regarding guarantees of certain
accounts payable and short-term borrowings of Woodward Marketing, LLC ("WMLLC").
Issuance of common stock. The Company issued a total of 849,481, 755,882
and 400,578 shares of common stock in 1999, 1998 and 1997, respectively, under
its various plans. See the Consolidated Statements of Shareholders' Equity and
Note 7 of the accompanying notes to consolidated financial statements for the
number of shares previously issued and available for future issuance under each
of the Company's plans.
15
<PAGE>
Future capital requirements
The Company believes that internally generated funds, its credit
facilities, commercial paper program and access to the public debt and equity
capital markets will provide necessary working capital and liquidity for capital
expenditures and other cash needs for fiscal 2000. The Company has access to
$262.0 million under its committed lines of credit and $74.0 million under its
uncommitted lines. A committed line of credit of $250.0 million is used to
support the Company's $250.0 million commercial paper program. In early fiscal
2000, the Company plans to seek regulatory approvals and register a shelf
offering with the SEC for the issuance from time to time of up to $500 million
in debt and equity securities for general corporate purposes.
Pro forma statement of cash flows for 1997
Because of the pooling of interests of Atmos, which has a September 30
fiscal year-end, with UCGC, which had a December 31 year-end, the activities of
UCGC for the quarter ended December 31, 1996 were included in the restated 1996
consolidated statement of cash flows instead of the 1997 consolidated statement
of cash flows. As a result, amounts in the 1997 consolidated statement of cash
flows as reported are different than they would have been, had they included a
full 12 month's activity for UCGC.
The following amounts summarize the pro forma condensed consolidated
statement of cash flows of Atmos and UCGC for the full 12 months ended September
30, 1997.
(In thousands)
Net cash provided by operating activities $ 60,278
Net cash used in investing activities (131,286)
Net cash provided by financing activities 68,267
---------
Decrease in cash (2,741)
Cash at beginning of year 8,757
---------
Cash at end of year $ 6,016
=========
16
<PAGE>
RESULTS OF OPERATIONS - CONSOLIDATED
Year ended September 30, 1999 compared with year ended September 30, 1998
To assist in management's discussion of results of operations, the following
table presents the effects of certain special items and weather on reported
consolidated net income. Earnings per share amounts presented in this
discussion are on a diluted basis.
Year ended September 30,
-------------------------------------------------
1999 1998 1997
---------------- -------------- --------------
Per Per Per
Amount Share Amount Share Amount Share
------- ----- ------- ----- ------- -----
(In thousands, except per share data)
Net income as reported $17,744 $ .58 $55,265 $1.84 $23,838 $ .81
Special items:
Management
reorganization - - - - 2,800 .10
Reserve for
integration costs - - - - 12,630 .43
Sale of assets - - (2,244) (.07) - -
Litigation settlement 2,070 .07 - - - -
------- ---- ------- ----- ------- -----
Normalized net income
except for effects
of weather 19,814 .65 53,021 1.77 39,268 1.34
Effects of weather 28,224 .91 3,485 .11 3,571 .12
------- ----- ------- ----- ------- -----
Normalized net income $48,038 $1.56 $56,506 $1.88 $42,839 $1.46
======= ===== ======= ===== ======= =====
Net income as reported
The Company reported net income of $17.7 million, or $.58 per diluted
share, on operating revenues of $690.2 million for the fiscal year ended
September 30, 1999. Net income for 1998 was $55.3 million, or $1.84 per diluted
share, on operating revenues of $848.2 million, which included one-time gains
totaling $2.2 million or $.07 per diluted share, from the sales of real estate
and equipment owned by the United Cities Division.
Results for the year were negatively impacted by the warmest winter on
record for Atmos. Across the Atmos system, weather was more than 15 percent
warmer than normal and more
17
<PAGE>
than 11 percent warmer than last year. Rainfall in West Texas exceeded average
rainfall levels for the region by more than 32% during the 1999 irrigation
season, resulting in a 43% decrease in irrigation sales over last year. In
addition, increased depreciation and interest expense related to assets placed
in service in advance of recognition in rates adversely affected financial
results. Earnings were also reduced by a charge in the second quarter of $.07
per share for settlement of litigation in Louisiana.
Net income for 1999 was also negatively impacted by operating and
maintenance expenses that were higher than last year as a result of the first
full year of operation of the Company's customer support center in Amarillo;
process improvement initiatives related to the new customer information and
billing system and the accounting and human resource systems placed in service
during the year; and Year 2000 readiness initiatives. Operation expenses also
included increased reserves of $5.0 million for the possible write-off of
accounts receivable resulting from a temporary suspension in service cutoffs and
normal efforts to collect past due receivables in connection with the Company's
conversion to the new customer information and billing system. In addition to
lower gross profit resulting from adverse weather conditions, gross profit for
the year was reduced $4.3 million by reserves established for deferred gas costs
that are not expected to be recoverable.
Finally, 1999 results were positively impacted by a change in accounting
principle adopted by WMLLC, a gas marketing and services company in which Atmos
owns a 45% interest. WMLLC adopted Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" ("EITF 98-10"), the effect of which added $2.4 million to other
income.
For fiscal year 1998, the Company reported net income of $55.3 million, or
$1.84 per diluted share, on operating revenues of $848.2 million. The 1998 net
income included one-time gains totaling $2.2 million or $.07 per diluted share,
from the sales of real estate and equipment. Although revenues for 1998 were
lower as a result of winter weather that was 5% warmer than normal, as well as
warmer than 1997, earnings improved due to gains on asset sales, lower operation
and maintenance expenses and increased irrigation sales. Operation and
maintenance expenses were lower for 1998 due to a company-wide restructuring of
the organization and Atmos' integration of the United Cities Division. Sales of
gas in West Texas to farmers for fueling irrigation pumps increased due to hot
and dry summer weather in
18
<PAGE>
1998. Irrigation volumes increased 34% in 1998 compared with 1997.
For fiscal year 1997, the Company reported net income of $23.8 million, or
$.81 per share, on operating revenues of $906.8 million. The 1997 net income
included the effects of special after-tax charges related to management
reorganization ($2.8 million or $.10 per share) and reserves related to the UCGC
merger and integration ($12.6 million or $.43 per share). Excluding the effect
of these charges, the Company's net income would have been $39.3 million or
$1.34 per share in 1997, compared with $41.2 million, or $1.42 per share for
1996. The 1997 results include UCGC, which merged with Atmos effective July 31,
1997.
Special items
The Company became successor in interest in connection with a lawsuit filed
against a gas company it acquired in Louisiana in 1995. In 1999 the Company
settled the lawsuit for $3.25 million or $2.07 million after-tax.
In 1998, the Company sold UCGC's former headquarters office building in
Brentwood, Tennessee; two office buildings and a piece of land in Franklin,
Tennessee that UCGC had held for investment; and an airplane. The Company
realized a pre-tax gain on the sale of assets totaling $3.3 million or $2.2
million after-tax.
In 1997 the Company completed a management reorganization and recorded a
charge of $4.4 million ($2.8 million after-tax) in related costs.
In connection with the UCGC merger and integration in 1997, the Company
recorded approximately $17.0 million of transaction costs and $42.8 million for
separation and other costs. The Company believes a significant amount of these
costs will be recovered through rates and future operating efficiencies of the
combined operations. Therefore, the Company recorded these costs as regulatory
assets and established a reserve of $20.3 million ($12.6 million after-tax), to
account for costs that may not be recovered. For further information regarding
the merger, see Note 2 of notes to consolidated financial statements.
19
<PAGE>
Consolidated Other Income, Interest Charges and Income Taxes
Other income
Equity in earnings of unconsolidated investment amounted to $7.2 million,
$3.9 million and $3.3 million for 1999, 1998 and 1997, respectively. The
increase for 1999 was primarily attributable to a change in accounting principle
adopted by WMLLC. WMLLC adopted EITF 98-10, the effect of which added $2.4
million to equity in earnings of unconsolidated investment.
Interest income was $.8 million, $1.5 million and $2.2 million for 1999,
1998 and 1997, respectively. The decreases in 1998 and 1999 were due to
maintaining lower overnight cash balances for short-term investing.
Other, net was $2.2 million, $4.3 million and $(.3) million for 1999, 1998
and 1997, respectively. The increase from 1997 to 1998 was primarily due to the
$3.3 million gain from sale of certain assets obtained in the merger with UCGC.
The $2.2 million in 1999 was primarily due to income from performance-based
rates ("PBR") which were implemented in Kentucky in 1998.
Interest charges
Interest charges totaled $37.1 million, $35.6 million and $33.6 million in
1999, 1998 and 1997, respectively. The increases for 1998 and 1999, were related
to increases in total debt outstanding for funding the infrastructure,
technology, process changes and customer support investments made in 1997, 1998
and 1999.
Income taxes
The provision for income taxes was $9.6 million, $31.8 million and $14.3
million for 1999, 1998 and 1997, respectively. Changes in income taxes are
primarily related to changes in pre-tax income. For further information
regarding income taxes, see Note 5 of notes to consolidated financial
statements.
Net income by segment
The Company has three business segments: utility operations, propane
operations and energy services, which includes the Company's 45% interest in
WMLLC. The following table sets forth the net income (loss) of each of these
segments for 1999, 1998 and 1997.
20
<PAGE>
Year ended September 30,
--------------------------------
1999 1998 1997
-------- -------- --------
(In thousands)
Utility $10,800 $43,332 $19,739
Propane (869) (66) (90)
Energy Services 7,813 11,999 4,189
------- ------- -------
Reported net income $17,744 $55,265 $23,838
======= ======= =======
For additional financial information regarding the Company's segments, see
Note 12 of notes to consolidated financial statements and the following
discussion of the "Results of Operations" for each segment.
21
<PAGE>
RESULTS OF OPERATIONS - UTILITY
Key financial and operating data for the Company's utility operations are
highlighted in the following table.
Year ended September 30,
---------------------------------
1999 1998 1997
---------- ---------- --------
Financial (Dollars in thousands,
- --------- except per Mcf data)
Operating revenues $ 621,211 $ 739,930 $807,428
Purchased gas cost 343,338 438,920 505,716
---------- ---------- --------
Gross profit 277,873 301,010 301,712
Operating expenses 225,623 200,345 240,499
Litigation settlement 3,250 - -
---------- ---------- --------
Operating income 49,000 100,665 61,213
Other income 2,763 843 1,242
Interest charges 35,799 33,181 30,882
Income taxes 5,164 24,995 11,834
---------- ---------- --------
Net income $ 10,800 $ 43,332 $ 19,739
========== ========== ========
Operating
- ---------
Sales volumes (MMcf):
Residential 67,128 73,472 75,215
Commercial 31,457 36,083 37,382
Public authority and other 5,793 4,937 5,195
Industrial 20,901 22,256 27,545
---------- ---------- --------
Total 125,279 136,748 145,337
Transportation (MMcf) 55,468 56,224 48,800
---------- ---------- --------
Total volumes (MMcf) 180,747 192,972 194,137
========== ========== ========
Meters in service,
end of year 1,037,995 1,004,532 985,448
Average gas sales price/Mcf $ 4.71 $ 5.17 $ 5.36
Average cost of gas/Mcf $ 2.74 $ 3.21 $ 3.48
Average margin per Mcf sold $ 1.97 $ 1.96 $ 1.88
Average transportation
revenue/Mcf $ .42 $ .43 $ .41
22
<PAGE>
Year ended September 30, 1999 compared with year ended September 30, 1998
Operating revenues decreased approximately 16% to $621.2 million in 1999
from $739.9 million in 1998 due to a decrease of 8% in sales volumes and a
decrease of 9% in the average sales price per thousand cubic feet ("Mcf") of gas
sold. The decrease in sales price reflects a decrease in the commodity cost of
gas, which is passed through to end users, and rate decreases implemented in
1998. Sales to weather sensitive residential, commercial and public authority
customers decreased approximately 10.1 billion cubic feet ("Bcf") in 1999 while
sales and transportation volumes delivered to industrial and agricultural
customers decreased approximately 2.1 Bcf. Total sales and transportation
volumes delivered decreased 6% to 180.7 Bcf in 1999, as compared with 193.0 Bcf
in 1998. The volume decrease was primarily due to lower demand as a result of
weather that was 11% warmer in 1999 than in 1998.
Gross profit decreased by approximately 8% to $277.9 million in 1999 from
$301.0 million in 1998. Factors contributing to the lower gross profit were a
decrease in sales volumes of 11.5 Bcf or 8% due to the effect of 11% warmer
weather than in 1998, rate decreases totaling approximately $1.8 million
implemented in fiscal 1998 in Colorado and Virginia and a reserve of $4.3
million established for deferred gas costs that are not expected to be
recoverable.
Operating expenses increased $25.3 million or 13% to $225.6 million in
1999. The increase in operating expenses was due to the first full year of
operation of the Company's Customer Support Center in Amarillo; process
improvement initiatives related to the new customer information and billing
system and the accounting and human resource systems placed in service during
the year; and Year 2000 readiness initiatives. Operation expenses also included
increased reserves of $5.0 million for the possible write-off of accounts
receivable resulting from a temporary suspension in service cutoffs and normal
efforts to collect past due receivables in connection with the Company's
conversion to the new customer information and billing system.
Year ended September 30, 1998 compared with year ended September 30, 1997
Utility operating revenues decreased approximately 8% to $739.9 million in
1998 from $807.4 million for 1997 due to a decrease of 6% in sales volumes and a
decrease of 4% in the average sales price per Mcf. The decrease in sales
volumes resulted from weather that was 3% warmer than 1997 and 5% warmer
23
<PAGE>
than 30-year normals. Sales volumes and revenues were also reduced by certain
industrial customers switching from sales service to transportation service.
Gross profit was not significantly changed at $301.0 million for 1998 as
compared with $301.7 million for 1997. The switching from sales to
transportation service did not significantly affect gross profit for 1998.
Operating expenses decreased $40.2 million for 1998 as compared with 1997
primarily due to a $20.3 million reserve for integration included in 1997, a
$4.4 million charge for a management reorganization in 1997, and a significant
reduction in 1998 operating expenses due to the company-wide restructuring of
the organization and the integration of the United Cities Division. Interest
charges increased 7% to $33.2 million primarily due to an increased level of
debt and slightly higher average short-term rates in 1998 as compared with 1997.
24
<PAGE>
RESULTS OF OPERATIONS - PROPANE
Key financial and operating data for the propane operations are presented
in the following table.
Year ended September 30,
---------------------------
1999 1998 1997
------- ------- ------
Financial (Dollars in thousands,
- --------- except per gallon data)
Operating revenues $22,944 $29,091 $33,194
Purchased gas cost 11,155 17,709 21,193
------- ------- -------
Gross profit 11,789 11,382 12,001
Operating expenses 12,332 10,763 11,596
------- ------- -------
Operating income(loss) (543) 619 405
Other income 482 174 159
Interest charges 1,231 897 744
Income tax benefit (423) (38) (90)
------- ------- -------
Net income (loss) $ (869) $ (66) $ (90)
======= ======= =======
Operating
- ---------
Propane heating degree days:
Actual 3,440 3,799 3,847
% of normal 85% 94% 96%
Sales volumes (000 gallons):
Retail 19,700 17,229 17,145
Wholesale 2,591 6,183 8,059
------- ------- -------
Total 22,291 23,412 25,204
======= ======= =======
Average selling price/gallon $.88 $.88 $.90
Average cost/gallon $.44 $.53 $.65
Customers, end of year 39,539 37,400 29,097
25
<PAGE>
Year ended September 30, 1999 compared with year ended September 30, 1998
Propane revenues decreased $6.2 million from $29.1 million in 1998 to $22.9
million in 1999 primarily due to decreased wholesale volumes sold as a result of
the implementation of the Company's plan to exit the wholesale propane supply
and transportation business. Partially offsetting this decrease was an increase
in the retail gallons sold as a result of the acquisitions of Ingas, Inc. in
May, 1998; Harris Propane Gas Company, Inc. in July 1998; Massey Propane Gas
Company and E-Con Gas, Inc. in August 1998; and Shaw LP Gas, Inc. in September
1998. The Company exited the less profitable propane transportation, cylinder
exchange, and appliance sales and service businesses in 1999.
Purchased gas cost decreased $6.5 million from $17.7 million in 1998 to
$11.2 million in 1999 due primarily to decreased wholesale volumes sold.
Additionally, the average cost per gallon decreased $.09 per gallon from $.53
per gallon in 1998 to $.44 per gallon in 1999. This decrease was partially
offset by the cost of increased retail gallons sold due to the acquisitions made
during fiscal 1998.
Operating expenses increased $1.6 million from $10.8 million in 1998 to
$12.3 million in 1999 due primarily to the acquisitions made during fiscal 1998.
Interest expense increased $.3 million due to increased debt related to the
acquisitions in 1998 and slightly higher interest rates in 1999.
Year ended September 30, 1998, compared with year ended September 30, 1997
Revenues from propane operations decreased from $33.2 million in 1997 to
$29.1 million in 1998 primarily due to the decreased selling price per gallon to
retail and wholesale customers. This decreased selling price was the result of
the lower demand because of warmer weather and increased competition for
customers as compared to the prior year. Partially offsetting this decrease was
an increase in retail gallon sales. The increase in retail volumes sold resulted
from the acquisitions discussed above.
Purchased gas cost decreased from $21.2 million in 1997 to $17.7 million in
1998 primarily due to the decreased market cost of propane to the Company
amounting to approximately $.12 per
26
<PAGE>
gallon. Partially offsetting this decrease was increased gas purchased for
retail sales in 1998 as compared to 1997.
Operating expenses decreased from $11.6 million in 1997 to $10.8 million in
1998 primarily due to decreased administrative and general expenses due to
decreased bad debt expense and a reduction of staff through attrition during
1998. Partially reducing this decrease was an increase in depreciation and
amortization from $2.1 million in 1997 to $2.3 million in 1998 due to the
acquisitions in 1997 and in 1998, and depreciation on additional plant placed in
service.
Interest expense increased from $.7 million in 1997 to $.9 million in 1998
due to increased short-term borrowings and long-term debt associated with the
acquisitions in 1998, as well as increased short-term borrowings to cover cash
flow deficits from decreased sales.
RESULTS OF OPERATIONS - ENERGY SERVICES
This segment is currently composed of four parts. Atmos Storage, Inc., owns
underground storage fields in Kansas and Kentucky and provides storage services
to the United Cities Division and Greeley Gas Company ("Greeley Division") and
other non-regulated customers. Atmos Energy Services, Inc., ("AESI") markets gas
to irrigation and industrial customers in West Texas through Enermart Energy
Services Trust ("Enermart"), and to industrial customers in Louisiana and is
developing plans for marketing various non-regulated services and products.
Atmos Energy Marketing, LLC, owns the Company's 45% investment in WMLLC, a gas
marketing and energy management services business. Atmos Leasing, Inc., leases
buildings and vehicles to the United Cities Division and gas appliances to
residential customers.
Key financial data for the energy services segment are set forth below.
27
<PAGE>
Year ended September 30,
--------------------------
1999 1998 1997
------- ------- ------
(Dollars in thousands)
Operating revenues $53,416 $80,672 $68,389
Purchased gas cost 43,284 61,228 52,448
------- ------- -------
Gross profit 10,132 19,444 15,941
Operating expenses 4,350 7,849 10,950
------- ------- -------
Operating income 5,782 11,595 4,991
Other income (loss) (96) 4,834 467
Equity in earnings of
unconsolidated investment 7,156 3,920 3,254
Interest charges 215 1,501 1,969
Income taxes 4,814 6,849 2,554
------- ------- -------
Net income $ 7,813 $11,999 $ 4,189
======= ======= =======
Gas Sales (MMcf)
Irrigation 9,655 17,018 12,743
Industrial 5,185 5,607 6,094
------- ------- -------
Total 14,840 22,625 18,837
======= ======= =======
Year ended September 30, 1999 compared with year ended September 30, 1998
Operating revenues decreased 34% from $80.7 million in 1998 to $53.4
million in 1999 due primarily to decreased West Texas non-regulated irrigation
and industrial revenues. The decrease in irrigation revenues was due to
increased rainfall and cooler summer temperatures in West Texas. Storage
revenues also decreased due to decreased volumes withdrawn from underground
storage as a result of warmer than normal winter weather in Kansas and
Tennessee.
Operating expenses decreased $3.5 million in 1999 due primarily to Enermart
entering into an all-inclusive gas transportation service agreement with the
Energas Division which resulted in costs which Enermart had previously
classified as operation expense being classified as cost of gas in 1999.
Decreased irrigation volumes in West Texas and storage withdrawals in Kansas and
Tennessee also reduced operating costs.
28
<PAGE>
Other income decreased $4.9 million in 1999 from 1998 primarily due to a
$3.3 million gain on sale of assets in 1998, as discussed below. Equity in
earnings of unconsolidated investment increased $3.2 million in 1999 from 1998
primarily because of the $2.4 million of income resulting from WMLLC's adoption
of EITF 98-10 in 1999. Interest charges decreased $1.3 million due primarily to
decreased short-term debt in 1999 as compared with 1998.
Year ended September 30, 1998 compared with year ended September 30, 1997
Operating revenues increased 18% from $68.4 million for 1997 to $80.7
million for 1998 due to increases of $10.7 million in non-regulated West Texas
irrigation and industrial revenues, and $1.6 million for gas storage operations.
The increase in irrigation and industrial revenues was primarily due to hotter
and drier than normal weather in West Texas in 1998. The increase in storage
revenues was due to increased volumes withdrawn from underground storage in 1998
as compared with 1997. Like the utility and propane operations, gas storage
volumes and revenues vary in relation to winter heating degree days.
Operating expenses decreased $3.1 million in 1998 as compared with 1997 due
primarily to operating efficiencies and cost savings from restructuring
irrigation and gas storage operations.
Other income increased to $4.8 million for 1998 as compared with $.5
million for 1997. The increase was primarily due to the sales of UCGC's former
headquarters office, two office buildings and a piece of land in Franklin,
Tennessee that UCGC had held for investment, and an airplane. Also contributing
to the increase was gas brokering and utilization of storage capacity in excess
of that dedicated to regulated markets to serve certain non-regulated markets.
Interest charges decreased $.5 million in 1998 as compared with 1997 due
primarily to reduced debt balances in Enermart, AESI's wholly-owned trust that
conducts non-regulated gas marketing operations in West Texas.
29
<PAGE>
Equity in earnings of WMLLC
The Company accounts for its 45% investment in WMLLC using the equity
method of accounting. Against the 45% of WMLLC's net income before tax, the
Company records the amortization of the excess of the purchase price over the
value of the net tangible assets, amounting to approximately $5.4 million which
was allocated to intangible assets consisting of customer contracts and
goodwill, and is being amortized over ten and twenty years, respectively, as
well as the provision for income taxes.
The following table presents the WMLLC financial results recorded by Atmos
for the years ended September 30, 1999, 1998 and 1997. WMLLC has adopted the
calendar year for financial reporting purposes.
Twelve months ended
September 30,
-----------------------
1999 1998 1997
------- ------ ------
(In thousands)
WMLLC net income before taxes $15,902 $8,711 $7,231
======= ====== ======
Atmos share @ 45% 7,156 3,920 3,254
Less:
Amortization of excess
purchase price 407 400 359
Provision for taxes 2,362 1,337 1,100
------- ------ ------
Atmos equity in WMLLC earnings $ 4,387 $2,183 $1,795
======= ====== ======
The net income before taxes of WMLLC increased from $7.2 million for 1997,
to $8.7 million for 1998, to $15.9 million for 1999, due to growth in number of
customers and gas marketing volumes and revenues each year. Additionally, WMLLC
adopted EITF 98-10 in 1999, the effect of which added $2.4 million to the
Company's equity in earnings of unconsolidated investment.
30
<PAGE>
Factors influencing future performance
Performance of the Company in the near future will primarily depend on the
results of its utility operations since utility operations are expected to
continue to be the substantial contributor to the Company's consolidated net
income. Because of the changing energy marketplace, there are several factors
that will influence Atmos' future financial performance. Some of these factors
are described below.
Allowed rate of return
The Company's utility business is subject to various regulated returns on
its rate base in each of the 12 states in which it operates. The Company
constantly monitors the allowed rates of return, its effectiveness in earning
such rates, and initiates rate proceedings or operating changes as needed.
Outcome of pending rate cases
In the normal course of the regulatory environment, assets are placed in
service and historical test periods are established before rate cases can be
filed. Once rate cases are filed, regulatory bodies have the authority to
suspend implementation of the new rates while studying the cases. Because of
this process, the Company must suffer the negative financial effects of having
placed assets in service without the benefit of rate relief. Management cannot
predict the outcome of the approximately $28.4 million of revenue increases it
is seeking in Texas and Kentucky.
Weather
The Company's natural gas and propane sales volumes and related revenues
are directly correlated with space heating requirements that result from cold
winter weather. Its agricultural sales volumes are associated with the rainfall
levels during the growing season in its West Texas irrigation market. Weather is
a significant factor influencing the Company's performance.
Control of expenses
Historically, the Company has been able to budget and control operating
expenses and investment within the amounts authorized to be collected in rates,
and intends to continue to do so. The ability to control expenses is an
important factor that will influence future results.
31
<PAGE>
Environmental matters
The Company is involved in certain environmental matters and expenditures
to comply with these laws and regulations are expected to be recovered through
rates, insurance, or shared with other potentially responsible parties. These
matters are not expected to materially affect the results of operations,
financial condition or cash flows of the Company. See Note 6 of notes to
consolidated financial statements for further information.
Performance-based regulation
Regulators in Georgia, Kentucky and Tennessee allow the Company and its
customers to share in purchased gas cost savings when the Company can obtain gas
supplies below certain benchmark indices. Acceptance of such incentives in other
states would contribute to the profitability of the Company's utility
operations.
Deregulation or unbundling
The Company is closely monitoring the development of unbundling initiatives
in the natural gas industry. Because of its brand loyalty in its service areas,
its enhanced technology and distribution system infrastructures, the Company
believes that it is now positively positioned as unbundling evolves.
Growth through acquisitions
Achieving economies of scale, thereby spreading the fixed costs of the
utility business over a large customer base is a basic tenet in the Company's
plan to continue to be a low cost provider among its industry peers.
Inflation
The Company believes that inflation has caused, and will continue to cause,
increases in certain operating expenses and has required and will continue to
require assets to be replaced at higher costs. The Company has a process in
place to continually review the adequacy of its gas rates in relation to the
increasing cost of providing service and the inherent regulatory lag in
adjusting those gas rates.
32
<PAGE>
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
Management is responsible for the preparation, presentation and integrity
of the financial statements and other financial information in this report. The
accompanying financial statements have been prepared in accordance with
generally accepted accounting principles, and include estimates and judgments
made by management that were necessary to prepare the statements in accordance
with such accounting principles.
The Company maintains a system of internal accounting controls designed to
provide reasonable assurance that assets are safeguarded from loss and that
transactions are executed and recorded in accordance with established
procedures. The concept of reasonable assurance is based on the recognition
that the cost of maintaining a system of internal accounting controls should not
exceed related benefits. The system of internal accounting controls is
supported by written policies and guidelines, internal auditing and the careful
selection and training of qualified personnel.
The financial statements have been audited by the Company's independent
auditors. Their audit was made in accordance with generally accepted auditing
standards, as indicated in the Report of Independent Auditors, and included a
review of the system of internal accounting controls and tests of transactions
to the extent they considered necessary to carry out their responsibilities for
the audit.
Management has considered the internal auditors' and the independent
auditors' recommendations concerning the Company's system of internal accounting
controls and has taken actions that are believed to be cost-effective in the
circumstances to respond appropriately to these recommendations. The Audit
Committee of the Board of Directors meets periodically with the internal
auditors and the independent auditors to discuss the Company's internal
accounting controls, auditing and financial reporting matters.
33
<PAGE>
REPORT OF INDEPENDENT AUDITORS
Board of Directors
Atmos Energy Corporation
We have audited the accompanying consolidated balance sheets of Atmos
Energy Corporation at September 30, 1999 and 1998, and the related consolidated
statements of income, shareholders' equity and cash flows for each of the three
years in the period ended September 30, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements 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
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles 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 opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Atmos Energy
Corporation at September 30, 1999 and 1998, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
September 30, 1999, in conformity with generally accepted accounting principles.
Ernst & Young LLP
Dallas, Texas
November 9, 1999
34
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
September 30,
----------------------
1999 1998
---------- ----------
(In thousands, except share data)
ASSETS
Property, plant and equipment $1,526,834 $1,333,556
Construction in progress 22,424 112,864
---------- ----------
1,549,258 1,446,420
Less accumulated depreciation
and amortization 583,476 528,560
---------- ----------
Net property, plant and equipment 965,782 917,860
Current assets
Cash and cash equivalents 8,585 4,735
Accounts receivable, less allowance
for doubtful accounts of $9,231
in 1999 and $1,969 in 1998 70,564 34,887
Inventories 8,209 15,219
Gas stored underground 44,653 48,909
Prepayments 3,142 3,630
---------- ----------
Total current assets 135,153 107,380
Deferred charges and other assets 129,602 116,150
---------- ----------
$1,230,537 $1,141,390
========== ==========
(continued)
35
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (continued)
September 30,
---------------------------
1999 1998
---------- ----------
(In thousands, except share data)
CAPITALIZATION AND LIABILITIES
Shareholders' equity
Common stock, no par value (stated
at $.005 per share); 100,000,000
shares authorized; issued and
outstanding: 1999 - 31,247,800
shares, 1998 - 30,398,319 shares $ 156 $ 152
Additional paid-in capital 293,359 271,637
Retained earnings 83,231 99,369
Accumulated other comprehensive
income 917 -
---------- ----------
Total shareholders' equity 377,663 371,158
Long-term debt 377,483 398,548
---------- ----------
Total capitalization 755,146 769,706
Current liabilities
Current maturities of long-term debt 17,848 57,783
Short-term debt 168,304 66,400
Accounts payable 64,167 44,742
Taxes payable 848 12,736
Customers' deposits 9,657 12,029
Other current liabilities 25,951 30,369
---------- ----------
Total current liabilities 286,775 224,059
Deferred income taxes 112,610 80,213
Deferred credits and other liabilities 76,006 67,412
---------- ----------
$1,230,537 $1,141,390
========== ==========
See accompanying notes to consolidated financial statements.
36
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended September 30,
------------------------------------
1999 1998 1997
-------- -------- --------
(In thousands, except per share data)
Operating revenues $690,196 $848,208 $906,835
Purchased gas cost 390,402 516,372 577,181
-------- -------- --------
Gross profit 299,794 331,836 329,654
Operating expenses
Operation 144,815 131,336 173,683
Maintenance 9,141 10,278 11,974
Litigation settlement 3,250 - -
Depreciation and amortization 56,874 47,555 45,257
Taxes, other than income 31,475 29,788 32,131
-------- -------- --------
Total operating expenses 245,555 218,957 263,045
-------- -------- --------
Operating income 54,239 112,879 66,609
Other income (expense)
Equity in earnings of
unconsolidated investment 7,156 3,920 3,254
Interest income 765 1,510 2,156
Other, net 2,202 4,341 (288)
-------- -------- --------
Total other income 10,123 9,771 5,122
Interest charges, net 37,063 35,579 33,595
-------- -------- --------
Income before income taxes 27,299 87,071 38,136
Income taxes 9,555 31,806 14,298
-------- -------- --------
Net income $ 17,744 $ 55,265 $ 23,838
======== ======== ========
Basic net income per share $ .58 $ 1.85 $ .81
======== ======== ========
Diluted net income per share $ .58 $ 1.84 $ .81
======== ======== ========
Cash dividends per share $ 1.10 $ 1.06 $ 1.01
======== ======== ========
Weighted average
shares outstanding:
Basic 30,566 29,822 29,409
======== ======== ========
Diluted 30,819 30,031 29,422
======== ======== ========
See accompanying notes to consolidated financial statements.
37
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common stock Accumulated
----------- Additional other
Number of Stated paid-in comprehensive Retained
shares value capital income earnings Total
------------ ------ ---------- ------------- -------- --------
(In thousands, except share data)
<S> <C> <C> <C> <C> <C> <C>
Balance, September 30, 1996 29,241,859 $146 $241,658 $ - $ 87,778 $329,582
Net income - - - - 23,838 23,838
Cash dividends ($1.01 per
share) - - - - (26,415) (26,415)
Common stock issued:
Restricted stock grant
plan 100,000 1 2,443 - - 2,444
Direct stock purchase
plans 85,243 - 1,888 - - 1,888
Outside directors
stock-for-fee plan 3,008 - 72 - - 72
ESOP 212,327 1 5,113 - - 5,114
Less: UCGC net income
for the quarter ended
December 31, 1996 - - - - (9,263) (9,263)
---------- ---- -------- ------------- -------- --------
Balance, September 30, 1997 29,642,437 148 251,174 - 75,938 327,260
Net income - - - - 55,265 55,265
Cash dividends ($1.06 per
share) - - - - (31,834) (31,834)
Common stock issued:
Restricted stock
grant plan 114,250 1 2,898 - - 2,899
Direct stock purchase
plan 531,353 3 14,482 - - 14,485
ESOP 52,473 - 1,485 - - 1,485
Long-term stock plan for
United Cities Division 55,500 - 1,533 - - 1,533
Outside directors
stock-for-fee plan 2,306 - 65 - - 65
---------- ---- -------- ------------- -------- --------
Balance, September 30, 1998 30,398,319 152 271,637 - 99,369 371,158
</TABLE>
(continued)
38
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (continued)
<TABLE>
<CAPTION>
Common stock Accumulated
----------------- Additional other
Number of Stated paid-in comprehensive Retained
shares value capital income earnings Total
---------- ------ ---------- ------------- --------- ---------
(In thousands, except share data)
<S> <C> <C> <C> <C> <C> <C>
Balance, September 30, 1998 30,398,319 $ 152 $271,637 $ - $ 99,369 $371,158
Comprehensive income
Net income - - - - 17,744 17,744
Unrealized holding gains
on investments, net - - - 917 - 917
Cash dividends ($1.10
per share) - - - - (33,882) (33,882)
Common stock issued:
Restricted stock
grant plan 56,850 - 1,732 - - 1,732
Direct stock purchase
plan 694,905 4 17,429 - - 17,433
ESOP 89,435 - 2,362 - - 2,362
Long-term stock plan for
United Cities Division 6,450 - 150 - - 150
Outside directors
stock-for-fee plan 1,841 - 49 - - 49
---------- ------ -------- ------------- -------- --------
Balance, September 30, 1999 31,247,800 $ 156 $293,359 $ 917 $ 83,231 $377,663
========== ====== ======== ============= ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
39
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
------------------------------
1999 1998 1997
-------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 17,744 $ 55,265 $ 14,575
Adjustments to reconcile net
income to net cash provided by
operating activities:
Depreciation and amortization:
Charged to depreciation and
amortization 56,874 47,555 39,970
Charged to other accounts 4,800 5,861 2,237
Deferred income taxes 31,874 (3,968) 5,807
Gain on sales of non-utility
assets - (3,335) -
Changes in assets and liabilities:
(Increase) decrease in accounts
receivable (35,677) 36,330 32,198
(Increase) decrease in
inventories 7,010 (2,886) 1,562
(Increase) decrease in gas
stored underground 4,256 (787) (4,772)
(Increase) decrease in
prepayments 488 2,387 (3,208)
Increase in deferred charges
and other assets (12,012) (20,671) (29,683)
Increase (decrease) in
accounts payable 19,425 (17,884) (17,695)
Increase (decrease) in taxes
payable (11,888) 8,673 (837)
Decrease in customers'
deposits (2,372) (3,069) (1,714)
Increase (decrease) in other
current liabilities (4,418) (22,213) 28,716
Increase in deferred credits
and other liabilities 8,594 10,393 1,593
-------- -------- --------
Net cash provided by
operating activities 84,698 91,651 68,749
(continued)
40
<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Year ended September 30,
---------------------------------
1999 1998 1997
--------- --------- ---------
(In thousands)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures $(110,353) $(134,989) $(122,312)
Retirements of property, plant
and equipment, net 757 178 1,189
Proceeds from sales of assets - 15,997 -
--------- --------- ---------
Net cash used in investing
activities (109,596) (118,814) (121,123)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in
short-term debt 101,904 (100,900) 38,812
Proceeds from issuance of
long-term debt - 154,445 40,000
Repayment of long-term debt (61,000) (16,296) (14,659)
Cash dividends paid (33,882) (31,834) (26,415)
Issuance of common stock 21,726 20,467 9,518
--------- --------- ---------
Net cash provided by
financing activities 28,748 25,882 47,256
--------- --------- ---------
Net increase (decrease) in cash
and cash equivalents 3,850 (1,281) (5,118)
Cash and cash equivalents at
beginning of year 4,735 6,016 11,134
--------- --------- ---------
Cash and cash equivalents
at end of year $ 8,585 $ 4,735 $ 6,016
========= ========= =========
See accompanying notes to consolidated financial statements.
41
<PAGE>
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Contents of Notes to Consolidated Financial Statements
1. Summary of significant accounting policies 43
2. Business combinations 49
3. Rates 50
4. Long-term debt and short-term debt 53
5. Income taxes 56
6. Contingencies 58
7. Common stock and stock options 63
8. Employee retirement and stock ownership 67
plans
9. Other postretirement benefits 72
10. Earnings per share 75
11. Statement of cash flows supplemental 76
disclosures
12. Segment information 76
13. Marketable securities 80
14. Leases 81
15. Related party transactions 82
16. Subsequent event 82
17. Selected quarterly financial data (unaudited) 83
42
<PAGE>
1. Summary of significant accounting policies
Forward-looking statements - These notes to consolidated financial
statements, particularly notes 2, 3, 6, 7, 9,14, and 16, may contain "forward-
looking statements" as discussed herein in Management's Discussion and Analysis
of Financial Condition and Results of Operations under the heading "Cautionary
Statement for the Purposes of the Safe Harbor under the Private Securities
Litigation Reform Act of 1995" and should be read in conjunction with such
discussion.
Description of business - Atmos Energy Corporation and its subsidiaries
("Atmos" or the "Company") are engaged primarily in the natural gas utility
business as well as certain non-regulated businesses. The Company distributes
through sales and transportation arrangements natural gas to approximately 1.0
million residential, commercial, public authority and industrial customers
through its five regulated utility divisions: Energas Company ("Energas
Division") in Texas; Trans Louisiana Gas Company ("Trans La Division") in
Louisiana; Western Kentucky Gas Company ("Western Kentucky Division") in
Kentucky; Greeley Gas Company ("Greeley Division") in Colorado and Kansas; and
United Cities Gas Company ("United Cities Division") in Illinois, Tennessee,
Iowa, Virginia, Georgia, South Carolina and Missouri. Such business is subject
to federal and state regulation and/or regulation by local authorities in each
of the twelve states in which the utility divisions operate. Its shared services
unit is located in Dallas, Texas and its Customer Support Center is located in
Amarillo, Texas. Its nonregulated businesses include propane sales and various
energy services businesses as described below.
The Company is engaged in the retail and wholesale distribution of propane
gas through United Cities Propane Gas, Inc. ("Propane"). It currently has
operation and storage centers and storefront offices located in Tennessee,
Kentucky, and North Carolina with a total company storage capacity of
approximately 2.5 million gallons. As of September 30, 1999, Propane served
approximately 40,000 customers in the states listed above as well as Virginia.
Through Atmos Storage, Inc. ("Storage"), the Company owns and operates
natural gas storage fields in Kentucky and Kansas to supplement natural gas used
by customers of the regulated utility divisions in Tennessee, Kansas and
Illinois and to provide storage services to other customers that may be in other
states.
43
<PAGE>
Through Atmos Energy Services, Inc., the Company markets gas to industrial
and irrigation customers in West Texas through Enermart Energy Services Trust
("Enermart") and to industrial customers in Louisiana, and is developing plans
for marketing various non-regulated services and products.
Through Atmos Energy Marketing, LLC's 45% interest in Woodward Marketing,
LLC ("WMLLC"), a limited liability company formed in Delaware with headquarters
in Houston, Texas, the Company is engaged in gas marketing and energy management
services. WMLLC provides gas supply management services to industrial customers,
municipalities and local distribution companies, including the Company's five
regulated utility divisions.
Finally, the Company, through Atmos Leasing Inc. and Atmos Energy
Marketing, LLC, leases real estate and vehicles to the United Cities Division
and leases appliances to residential customers.
Principles of consolidation - The accompanying consolidated financial
statements include the accounts of Atmos Energy Corporation and its
subsidiaries. Each subsidiary is wholly owned and intercompany transactions have
been eliminated.
Accounting for unconsolidated investments - The Company accounts for its
45% interest in WMLLC using the equity method of accounting for investments.
Equity in pre-tax earnings of WMLLC included in the consolidated statement of
income was $7.2 million, $3.9 million and $3.3 million in 1999, 1998 and 1997,
respectively. The Company amortizes the excess of the purchase price over the
value of the net tangible assets, amounting to approximately $5.4 million, which
was allocated to intangible assets consisting of customer contracts and goodwill
over 10 and 20 years, respectively. WMLLC adopted Emerging Issues Task Force 98-
10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," ("EITF 98-10"). EITF 98-10 requires that energy trading contracts
should be marked to market (that is, measured at fair value determined as of the
balance sheet date) with the gains and losses included in earnings and
separately disclosed. Atmos' 45% after-tax share of WMLLC's income from the
adoption of EITF 98-10 was $2.4 million or $.08 per share.
Restatement for pooling of interests - The consolidated financial
statements for all periods prior to July 31, 1997 have been restated for the
pooling of interests of the Company with United Cities Gas Company. Certain
changes in account
44
<PAGE>
classifications have been made to conform United Cities Gas Company's
classifications to Atmos' presentation.
Regulation - The Company's utility operations are subject to regulation
with respect to rates, service, maintenance of accounting records and various
other matters by the respective regulatory authorities in the states in which it
operates. Atmos' accounting policies recognize the financial effects of the
ratemaking and accounting practices and policies of the various regulatory
commissions. Regulated utility operations are accounted for in accordance with
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation." This statement requires cost-based rate
regulated entities that meet certain criteria to reflect the authorized recovery
of costs due to regulatory decisions in their financial statements.
The Company records regulatory assets which represent assets which are
being recovered through customer rates or are probable of being recovered
through customer rates. Significant regulatory assets as of September 30, 1999
included the following: merger and integration costs of $35.9 million, net of
related reserve, environmental costs of $3.9 million, and deferred cost of
purchased gas of $.5 million. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process. As of September 30, 1999, the Company
had recorded a regulatory liability of $2.2 million for deferred income taxes.
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.
Utility property, plant and equipment - Utility property, plant and
equipment is stated at original cost net of contributions in aid of
construction. The cost of additions includes direct construction costs, payroll
related costs (taxes, pensions and other fringe benefits), administrative and
general costs, and the estimated cost of an allowance for funds used during
construction (See AFUDC below). Major renewals and betterments are capitalized,
while the costs of maintenance and
45
<PAGE>
repairs are charged to expense as incurred. The costs of large projects are
accumulated in construction in progress until the project is completed. When the
project is completed, tested and placed in service, the balance is transferred
to the utility plant in service account, included in rate base and depreciation
begins. Property, plant and equipment is depreciated at various rates on a
straight-line basis over the estimated useful lives of the assets. The composite
rates were 4.0%, 4.0% and 3.9% for 1999, 1998 and 1997, respectively. At the
time property, plant and equipment is retired, the cost, plus removal expenses
less salvage, is charged to accumulated depreciation.
Allowance for funds used during construction ("AFUDC") - AFUDC represents
the estimated cost of funds used to finance the construction of major projects.
Under regulatory practices, the costs are capitalized and included in rate base
for ratemaking purposes when the completed projects are placed in service.
Interest expense of $3.7 million, $4.1 million and $1.2 million was capitalized
in 1999, 1998 and 1997, respectively. The increased amounts in 1999 and 1998
were related to the Customer Support Center and customer information, accounting
and human resource technology systems that were completed and placed in service
in 1999.
Non-utility property, plant and equipment - Balances are stated at cost and
depreciation is computed generally on the straight-line method for financial
reporting purposes.
Inventories - Inventories consist primarily of materials and supplies and
merchandise held for resale. These inventories are stated at the lower of
average cost or market. Inventories also include propane inventories of $768,000
and $979,000 at September 30, 1999 and 1998, respectively. Propane is priced at
average cost.
Gas stored underground - Net additions of inventory gas to storage and
withdrawals of inventory gas from storage are priced using the average cost
method for all Atmos utility divisions, except for the United Cities Division,
where it is priced on the first-in first-out method. Gas stored underground and
owned by Storage is priced on the last-in first-out ("LIFO") method. In
accordance with the United Cities Division's purchased gas adjustment ("PGA")
clause, the liquidation of a LIFO layer would be reflected in subsequent gas
adjustments in customer rates and does not affect the results of operations.
Noncurrent gas in storage is classified as property, plant and equipment and is
priced at cost.
46
<PAGE>
Income taxes - Income taxes are provided based on the deferred method,
resulting in income tax assets and liabilities due to temporary differences.
Temporary differences are differences between the tax bases of assets and
liabilities and their reported amounts in the financial statements that will
result in taxable or deductible amounts in future years. The deferred method
requires the effect of tax rate changes on current and accumulated deferred
income taxes to be reflected in the period in which the rate change was enacted.
The deferred method also requires that deferred tax assets be reduced by a
valuation allowance unless it is more likely than not that the assets will be
realized.
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, 1999 and 1998 include merger and integration costs of $35.9
million and $39.5 million in 1999 and 1998, respectively, net of the related
reserve for possible non-recovery; and the investment in WMLLC of $16.0 million
and $11.9 million in 1999 and 1998, respectively. Also included in deferred
charges and other assets are assets of the Company's qualified defined benefit
retirement plans in excess of the plans' obligations, Company assets related to
the nonqualified retirement plans, unamortized debt expense, and deferred
compensation expense related to non-vested restricted stock grants.
Deferred credits and other liabilities - Deferred credits and other
liabilities include customer advances for construction, obligations under
capital leases, obligations under other postretirement benefits, and obligations
under the Company's nonqualified retirement plans.
Earnings per share - The calculation of basic earnings per share is based
on net income divided by the weighted average number of common shares
outstanding. The calculation of diluted earnings per share is based on net
income divided by the weighted average number of shares outstanding plus the
dilutive shares related to the United Cities Division's Long-term Stock Plan and
Atmos' Restricted Stock Grant Plan.
Segment Information - In 1999, the Company adopted Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and
Related Information," ("SFAS No. 131"). SFAS No. 131 supersedes Statement of
Financial Accounting Standards No. 14, "Financial
47
<PAGE>
Reporting for Segments of a Business Enterprise," replacing the "industry
segment" approach with the "management" approach. The management approach
requires financial information to be disclosed for segments whose operating
results are reviewed by the "chief operating decision maker." It also requires
related disclosures about products and services. The adoption of SFAS No. 131
did not affect results of operations or financial position, but did affect the
disclosure of segment information.
Comprehensive Income - In 1999, the Company adopted Statement of Financial
Accounting Standards No. 130, "Reporting Comprehensive Income." This statement
requires reporting of comprehensive income and its components (revenues,
expenses, gains and losses) in any complete presentation of general purpose
financial statements. Comprehensive income describes all changes, except those
resulting from investments by owners and distributions to owners, in the equity
of a business enterprise from transactions and other events including, as
applicable, foreign-currency items, minimum pension liability adjustments and
unrealized gains and losses on certain investments in debt and equity
securities. While the primary component of comprehensive income is the Company's
reported net income, the other components of comprehensive income relate to
unrealized gains and losses associated with certain investments held as
available for sale.
Use of estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Reclassifications - Certain prior year amounts have been reclassified to
conform with the current year presentation.
Recently Issued Accounting Standards Not Yet Adopted - The Company has not
yet adopted Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The Statement will be effective
for the Company's fiscal year 2001. It establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. This Statement does not
allow retroactive application to financial statements of prior periods. The
Company's management is currently in the process of
48
<PAGE>
evaluating the impact of adopting this Statement on its reported financial
condition, results of operations and cash flows.
2. Business combinations
On July 31, 1997, Atmos acquired by means of a merger all of the assets and
liabilities of United Cities Gas Company ("UCGC") in accordance with the terms
and provisions of an Agreement and Plan of Reorganization dated July 19, 1996
and amended October 3, 1996. A total of 13,320,221 shares of Atmos common stock
was issued in a one-for-one exchange for all outstanding shares of UCGC common
stock.
UCGC was merged with and into Atmos by means of a tax-free reorganization.
The transaction was accounted for as a pooling of interests; therefore,
historical financial statements for periods prior to the merger were restated.
Following the merger, UCGC's business began operating as United Cities Gas
Company, a division of Atmos ("United Cities Division") and integration of the
companies began. The United Cities Division is structured like other divisions
of Atmos. To achieve this structure, approximately 560 utility positions in the
United Cities Division were eliminated by September 1998. An additional 75 Atmos
positions were eliminated as part of the integration, resulting in approximately
635 total position reductions in the combined Company by September 1998. Atmos
also initiated plans to enhance its customer service in Texas, Louisiana,
Kentucky, Colorado, Kansas and Missouri through business process changes which
resulted in a net reduction of approximately 240 positions. These changes
included restructuring business office operations, establishing a network of
payment centers and creating a customer support center, and installing a new
customer information center.
During fiscal 1997 and 1998, the Company recorded as regulatory assets the
costs of the merger and integration of the United Cities Division. The Company
believes there are substantial long term benefits to its customers and
shareholders from the merger of the two companies. The Company believes a
significant amount of the costs to achieve these benefits will be recovered
through rates and future operating efficiencies of the combined operations.
Therefore, the merger and integration costs are being charged to operations
concurrent with the benefits received. However, in the fourth quarter of fiscal
1997 the Company established a general reserve of approximately $20.3 million
($12.6 million after-tax), to account for costs that may not be recovered
through rates.
49
<PAGE>
3. Rates
The following is a discussion of the Company's ratemaking activity for rate
cases that are currently pending as of September 30, 1999 or rate proceedings
completed during the three years ended September 30, 1999.
In August 1999, the Energas Division filed rate cases in its West Texas
System cities and Amarillo, Texas, requesting rate increases totaling
approximately $13.2 million. In addition to the rate increase to recover
investments in technology and distribution plant expansion and maintenance, the
proposed rate design would increase the customer charge, reducing the impact on
earnings of warmer than normal winter weather. Pursuant to Texas law,
municipalities have original jurisdiction in the establishment of rates. The
City of Amarillo has until December 1999 to decide on the rate request and the
West Texas Cities have until January 2000. If the Company and the cities cannot
agree on the amount of a rate increase, the Company must appeal to the Railroad
Commission of Texas and a final resolution could be expected in the summer of
2000. Later in 1999 or early 2000, the Company plans to request a rate increase
of approximately $1.1 million in the environs areas outside the city limits of
the West Texas System cities and Amarillo, Texas for total increases of $14.3
million being sought in Texas. Rates in areas outside the city limits in Texas
are subject to the jurisdiction of the Railroad Commission of Texas. Management
cannot predict the outcomes of these rate proceedings.
In June 1999, the Trans La Division appeared before the Louisiana Public
Service Commission for a rate investigation and to redesign rates to mitigate
the effects of warm winter weather. A decision was rendered by the Louisiana
Commission in October 1999 that increased service charges associated with
customer service calls and increased the monthly customer charges from $6 to $9,
both effective November 1, 1999. While these changes are revenue neutral, this
will mitigate the impact of warmer than normal winter weather on earnings. The
decision also included a three-year rate stabilization clause, which will allow
the Trans La Division's rates to be adjusted annually to allow the Company to
earn a minimum return on equity of 10.5%.
In May 1999, the Western Kentucky Division requested from the Kentucky
Public Service Commission an increase in revenues of approximately $14.1
million, a weather normalization adjustment ("WNA") and changes in rate design
to shift a portion of revenues from commodity charges to fixed rates. The WNA,
if approved, would be similar to what the Company has in Georgia
50
<PAGE>
and Tennessee and would be in effect from November through April, beginning in
November 2000. The Kentucky Commission suspended the proposed rates for six
months in July 1999. It must, by statute, make a decision by April 2000.
Management cannot predict the outcome of this rate proceeding.
In fiscal 1997, the Colorado Office of Consumer Counsel filed a complaint
with the Colorado Public Utilities Commission ("Colorado Commission")requesting
a $3.5 million reduction in the annual revenues in Colorado of the Greeley
Division. On December 17, 1997, a hearing was held at the Colorado Commission
presenting a Stipulation and Agreement reached by the Greeley Division and the
Colorado Office of Consumer Counsel. It settled the Consumer Counsel's complaint
against the Greeley Division for a $1.6 million reduction in annual revenues.
The Stipulation and Agreement became effective in January 1998. The reduction
decreased 1998 gross profit of the Greeley Division by approximately 4% and the
gross profit of the Company by approximately .5%.
On June 9, 1998, the Kentucky Public Service Commission issued an Order
approving an Experimental Performance-based Ratemaking ("PBR") mechanism related
to gas procurement and gas transportation activities filed by the Western
Kentucky Division. The PBR mechanism is incorporated into the Western Kentucky
Division's Gas Cost Adjustment Clause. It provides for sharing of purchased gas
cost savings between the consumers and the Company. The Company recognized other
income of $2.0 million under the Kentucky PBR in fiscal 1999.
Effective April 1, 1999, the Tennessee Regulatory Authority approved the
United Cities Division's request to continue its PBR mechanism related to gas
procurement and gas transportation activities for a three-year period. The
Authority revised the mechanism from the original two-year experimental period,
by increasing the cap for incentive gains and/or losses to $1.25 million per
year. Similar to Tennessee, the Georgia Public Service Commission renewed the
Company's PBR program for an additional three years effective May 1, 1999. The
gas purchase and capacity release mechanisms of the PBRs are designed to provide
the Company incentives to find innovative methods to lower gas costs to its
customers. The Company recognized other income of $176,000 in fiscal year 1999
for the Georgia and Tennessee PBRs.
The Georgia Public Service Commission and the Tennessee Regulatory
Authority approved WNAs in fiscal 1991 and 1992, respectively. The WNAs,
effective October through May each year in Georgia and November through April
each year in Tennessee,
51
<PAGE>
allow the United Cities Division to increase the base rate portion of customers'
bills when weather is warmer than normal and decrease the base rate when weather
is colder than normal. The net effect of the WNA was an increase in revenues of
$4.4 million, $.7 million and $2.6 million in 1999, 1998 and 1997, respectively.
52
<PAGE>
4. Long-term debt and short-term debt
Long-term debt at September 30, 1999 and 1998 consisted of the following:
1999 1998
-------------- ---------
Unsecured 11.2% Senior Notes, (In thousands)
due 2002, payable in annual
installments of $2,000 $ 8,000 $ 10,000
Unsecured 9.76% Senior Notes,
due 2004, payable in annual
installments of $3,000 18,000 21,000
Unsecured 9.57% Senior Notes,
due 2006, payable in annual
installments of $2,000 14,000 16,000
Unsecured 7.95% Senior Notes,
due 2006, payable in annual
installments of $1,000 7,000 8,000
Unsecured 10% Notes, due 2011 2,303 2,303
Unsecured 8.07% Senior Notes, due 2006,
payable in annual installments of
$4,000 beginning 2002 20,000 20,000
Unsecured 8.26% Senior Notes, due 2014,
payable in annual installments of
$1,818 beginning 2004 20,000 20,000
Medium term notes
Series A, 1995-1, 6.67%, due 2025 10,000 10,000
Series A, 1995-2, 6.27%, due 2010 10,000 10,000
Series A, 1995-3, 6.20%, due 2000 2,000 2,000
Unsecured 6.09% Note, due November 1998 - 40,000
Unsecured 6.75% Debentures, due 2028 150,000 150,000
First Mortgage Bonds
Series J, 9.40% due 2021 17,000 17,000
Series N, 8.69% due 2000 1,000 3,000
Series P, 10.43% due 2017 22,500 25,000
Series Q, 9.75% due 2020 20,000 20,000
Series R, 11.32% due 2004 10,720 12,860
Series T, 9.32% due 2021 18,000 18,000
Series U, 8.77% due 2022 20,000 20,000
Series V, 7.50% due 2007 10,000 10,000
Rental property, propane and other
term notes due in installments
through 2013 14,808 21,168
-------- --------
Total long-term debt 395,331 456,331
Less current maturities (17,848) (57,783)
-------- --------
$377,483 $398,548
======== ========
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<PAGE>
Most of the Senior Notes and First Mortgage Bonds contain provisions that
allow the Company to prepay the outstanding balance in whole at any time,
subject to a prepayment premium. The Senior Note agreements and First Mortgage
Bond indentures 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 September 30, 1999, approximately $44.8 million
of retained earnings was unrestricted.
As of September 30, 1999, all of the Greeley Division utility plant assets
with a net book value of approximately $173.7 million are subject to a lien
under the 9.4% Series J First Mortgage Bonds assumed by the Company in the
acquisition of Greeley Gas Company. Also, substantially all of the United Cities
Division utility plant assets, totaling approximately $293.0 million, are
subject to a lien under the Indenture of Mortgage of the Series N through V
First Mortgage Bonds.
Based on the borrowing rates currently available to the Company for debt
with similar terms and remaining average maturities, the fair value of long-term
debt at September 30, 1999 and 1998 is estimated, using discounted cash flow
analysis, to be $387.7 million and $489.0 million, respectively. It is not
currently advantageous for the Company to refinance its long-term debt because
of costs of prepayment required in the various debt agreements.
Maturities of long-term debt at September 30, 1999 are as follows (in
thousands):
2000 $ 17,848
2001 15,434
2002 15,323
2003 20,995
2004 17,656
Thereafter 308,075
--------
$395,331
========
Short-term debt
At September 30, 1999, short-term debt was composed of $152.7 million of
commercial paper and $15.6 million outstanding
54
<PAGE>
under bank credit facilities. At September 30, 1998, it was composed of $66.4
million outstanding under bank credit facilities. The weighted average interest
rate on short-term borrowings outstanding was 5.7% and 6.2% at September 30,
1999 and 1998, respectively.
Committed credit facilities
The Company has two short-term committed credit facilities. The committed
lines are renewed or renegotiated at least annually. One short-term unsecured
credit facility from a group of 10 banks is for $250.0 million. This facility
expires in August 2000. No balance was outstanding under this facility at
September 30, 1999 or 1998. This facility requires a commitment fee of .08% on
the unused portion. A second facility is for $12.0 million with a single bank.
This facility expires April 1, 2000. It requires a commitment fee of .05% on the
unused portion. Borrowings totaling $12.0 million were outstanding under this
facility at both September 30, 1999 and 1998.
Uncommitted credit facilities
The Company also has unsecured short-term uncommitted credit lines from two
banks totaling $74.0 million. Borrowings under uncommitted credit facilities
totaled $3.6 million and $54.4 million at September 30, 1999 and 1998,
respectively. These uncommitted lines expire in May and August 2000, and are
renewed or renegotiated at least annually. 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.
Commercial paper program
The Company implemented a $250.0 million commercial paper program in
October 1998. It is supported by the $250.0 million committed line of credit
described above. The Company's commercial paper was rated A-2 by Standard and
Poor's and P-2 by Moody's. A total of $152.7 million of commercial paper was
outstanding at September 30, 1999.
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<PAGE>
5. Income taxes
The components of income tax expense for 1999, 1998 and 1997 are as
follows:
1999 1998 1997
--------- -------- --------
(In thousands)
Current
Federal $(18,761) $31,694 $ 7,917
State (4,081) 4,503 1,000
Deferred
Federal 27,370 (3,352) 4,807
State 5,321 (616) 1,000
Investment tax credits (294) (423) (426)
-------- ------- -------
$ 9,555 $31,806 $14,298
======== ======= =======
Deferred income taxes reflect the tax effect of differences between the
basis of assets and liabilities for book and tax purposes. The tax effect of
temporary differences that give rise to significant components of the deferred
tax liabilities and deferred tax assets at September 30, 1999 and 1998 are
presented below:
56
<PAGE>
1999 1998
---------- ----------
(In thousands)
Deferred tax assets:
Costs expensed for book purposes
and capitalized for tax purposes $ 629 $ 1,049
Accruals not currently deductible
for tax purposes 12,657 7,189
Customer advances 4,535 3,730
Nonqualified benefit plans 7,947 11,297
Postretirement benefits 10,356 10,093
Unamortized investment tax credit 1,304 1,427
Regulatory liabilities 3,159 3,175
Tax net operating loss and credit
carryforwards 12,504 -
Other, net 4,787 2,838
--------- ---------
Total deferred tax assets 57,878 40,798
Deferred tax liabilities:
Difference in net book value
and net tax value of assets (139,324) (114,229)
Pension funding (5,480) (4,120)
Gas cost adjustments 3,997 8,943
Regulatory assets (4,462) (4,941)
Cost capitalized for book
purposes and expensed for
tax purposes (19,112) -
Other, net (6,107) (6,664)
--------- ---------
Total deferred tax liabilities (170,488) (121,011)
--------- ---------
Net deferred tax liabilities $(112,610) $ (80,213)
========= =========
SFAS No. 109 deferred accounts for
rate regulated entities (included
in other deferred credits) $ 1,896 $ 1,548
========= =========
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<PAGE>
Reconciliations of the provisions for income taxes computed at the
statutory rate to the reported provisions for income taxes for 1999, 1998 and
1997 are set forth below:
1999 1998 1997
------- -------- --------
(In thousands)
Tax at statutory rate of 35% $9,555 $30,474 $13,348
Common stock dividends deductible
for tax reporting (701) (695) (706)
State taxes 841 2,526 1,300
Other, net (140) (499) 356
------ ------- -------
Provision for income taxes $9,555 $31,806 $14,298
====== ======= =======
The Company has net operating loss carryforwards amounting to $23.9 million
which will expire in the year 2019. The Company also has tax credit
carryforwards amounting to $4.1 million, the majority of which represent
alternative minimum tax credits which do not expire.
6. Contingencies
Litigation
Trans La Division
In November 1997, a jury in Plaquemine, Louisiana awarded Brian L. Heard
General Contractor, Inc., ("Heard") a total of approximately $178,000 in actual
damages and $15 million in punitive damages resulting from a lawsuit by Heard
against the Trans La Division, the successor in interest to Oceana Heights Gas
Company, which the Company acquired in November 1995. The trial judge also
awarded interest on the total judgment amount. The claims were for events that
occurred prior to the time Atmos acquired Oceana Heights Gas Company. Heard
filed the suit against the Trans La Division and two other defendants, alleging
that gas leaks had caused delays in Heard's completion of a sewer project,
resulting in lost business opportunities for the contractor during 1994. The
Company immediately appealed the verdict. However, on March 24, 1999, the
Company announced that it had reached a settlement of the case as a result of
mediation discussions. The parties agreed to settle the case for $3.5 million.
In the settlement, neither Atmos nor the Trans La Division conceded liability.
Atmos paid $3.25 million and the remaining $.25 million was paid by Oceana
Heights Gas Company's insurers. In exchange, the Company obtained a full release
from Heard of all claims against Atmos and the Trans La Division.
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<PAGE>
Greeley Division
In Colorado, the Greeley Division is a defendant in several lawsuits filed
as a result of a fire in a building in Steamboat Springs, Colorado on February
3, 1994. The plaintiffs claimed that the fire resulted from a leak in a severed
gas service line owned by the Greeley Division. On January 12, 1996, the jury
awarded the plaintiffs approximately $2.5 million in compensatory damages and
approximately $2.5 million in punitive damages. The jury assessed the Company
with liability for all of the damages awarded. The Company appealed the judgment
to the Colorado Court of Appeals, which reversed the trial court verdict and
ordered a new trial. The Colorado Supreme Court upheld the Court of Appeals
reversal and order for a new trial. As a result of mediation, a settlement was
reached with five of the claimants, leaving only three remaining claimants with
aggregate claims of approximately $2 million. The Company does not expect the
final outcome of this case to have a material adverse effect on the financial
condition, the results of operations or the cash flows of the Company because
the Company believes it has adequate insurance and reserves to cover any damages
that may ultimately be awarded.
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 the
Company and the Greeley Gas 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, accuse the defendants of
underpaying royalties on gas taken from wells situated on non-federal 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 do 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. Since the filing of the
petition, this case has been removed to the United States District Court in
Wichita, Kansas, where there are numerous and various motions pending, including
a request for remand by the plaintiffs as well as a notice filed to consolidate
this case with other similar pending litigation in federal court in Wyoming in
which the Company is also a defendant along with over 200 other defendants, the
case of Jack J. Grynberg, on behalf of the United States of America.
59
<PAGE>
The Company believes that the plaintiffs' claims are lacking in merit and
intends to vigorously defend this action. However, the Company cannot assess, at
this time, the likelihood of whether or not the plaintiffs may prevail on any
one or more of their asserted claims. In any event, the Company does not expect
the final outcome of this case to have a material adverse effect on the
financial condition, the results of operations or the net cash flows of the
Company because the Company believes that it has adequate reserves to cover any
damages that may ultimately be awarded.
The Company is a party to other litigation matters and claims that arise
out of the ordinary business of the Company. While the results of these
litigation matters and claims cannot be predicted with certainty, the Company
does not believe the final outcome of such litigation and claims will have a
material adverse effect on the financial condition, the results of operations or
the cash flows of the Company because the Company believes that it has adequate
insurance and reserves to cover any damages that may ultimately be awarded.
Guarantees
The Company's wholly-owned subsidiary, Atmos Energy Marketing, LLC ("AEM"),
and Woodward Marketing, Inc. ("WMI"), sole members of Woodward Marketing, LLC
("WMLLC"), act as guarantors of up to $12.5 million of balances outstanding
under a $30.0 million bank credit facility for WMLLC. AEM guarantees the payment
of up to $5.6 million of borrowings under this facility. No balance was
outstanding under this credit facility at September 30, 1999. AEM and WMI also
act as joint and several guarantors on payables of WMLLC up to $40.0 million of
natural gas purchases and transportation services from suppliers. WMLLC payable
balances outstanding that were subject to these guarantees amounted to $18.8
million at September 30, 1999.
60
<PAGE>
Environmental Matters
The United Cities Division is the owner or previous owner of manufactured
gas plant sites in Keokuk, Iowa; Johnson City and Bristol, Tennessee; and
Hannibal, Missouri, which were used to supply gas prior to availability of
natural gas. The gas manufacturing process resulted in certain by-products and
residual materials including coal tar. The manufacturing process used by the
Company was an acceptable and satisfactory process at the time such operations
were being conducted. Under current environmental protection laws and
regulations, the Company may be responsible for response actions with respect to
such materials, if response actions are necessary.
As of September 30, 1999, the Company had accrued and deferred for recovery
$1.1 million, including $258,000 that was incurred for an insurance
recoverability study, and $750,000 for the investigations of the Johnson City
and Bristol, Tennessee and Hannibal, Missouri sites. As of September 30, 1999,
the Company has incurred costs of approximately $492,000 for these sites.
Iowa sites
In June 1995, UCGC entered into an agreement to pay $1.8 million to Union
Electric Company, now Ameren, whereby Union Electric agreed to assume
responsibility for UCGC's continuing investigation and environmental response
action obligations as outlined in the feasibility study related to a former
manufactured gas plant in Keokuk. The $1.8 million was paid in five annual
installments, with the last installment being paid in July 1999. In a rate case
effective June 1, 1996, UCGC began collecting increased rates which included a
10-year amortization of the $1.8 million payment to Union Electric.
Tennessee sites
UCGC and the Tennessee Department of Environment and Conservation entered
into a consent order effective January 23, 1997, for the purpose of facilitating
the investigation, removal and remediation of the Johnson City site. UCGC began
the implementation of the consent order in the first quarter of 1997 which
continued throughout fiscal year 1999.
The Company is unaware of any information which suggests that the Bristol
site gives rise to a present health or environmental risk as a result of the
manufactured gas process or that any response action will be necessary.
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<PAGE>
The Tennessee Regulatory Authority granted UCGC permission to defer, until
its next rate case, all costs incurred in Tennessee in connection with state and
federally mandated environmental control requirements.
Missouri sites
On July 22, 1998, Atmos entered into an Abatement Order on Consent with the
Missouri Department of Natural Resources addressing the former manufactured gas
plant located in Hannibal, Missouri. Atmos, through its United Cities Division,
agreed in the order to perform a removal action, a subsequent site evaluation
and to reimburse the response costs incurred by the 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. On
March 9, 1999, the Missouri Public Service Commission issued an Order
authorizing Atmos to defer the costs associated with this site until the next
rate increase, which must be proposed before March 9, 2001.
Kansas sites
Atmos is currently conducting investigation and remediation activities
pursuant to Consent Orders between the Kansas Department of Health and
Environment ("KDHE") and UCGC. The Orders provide for the investigation and
remediation of mercury contamination at gas pipeline sites which utilize or
formerly utilized mercury meter equipment in Kansas. As of September 30, 1999,
the Company had identified approximately 720 sites where mercury may have been
used and had incurred $100,000 for recovery. In addition, based upon available
current information, the Company accrued and deferred for recovery an additional
$280,000 for the investigation of these sites. The Kansas Corporation Commission
has authorized the Company to defer these costs and seek recovery in a future
rate case.
The Company is a party to other environmental matters and claims that arise
out of the ordinary business of the Company. While the ultimate results of
response actions to these environmental matters and claims cannot be predicted
with certainty, the Company does not believe the final outcome of such response
actions will have a material adverse effect on the financial condition, the
results of operations or the cash flows of the Company because the Company
believes that the expenditures related to such response actions will either be
recovered through rates, shared with other parties, or covered by adequate
insurance or reserves.
62
<PAGE>
7. Common stock and stock options
Shareholders' Rights Plan
On November 12, 1997, the Board of Directors approved a new Rights
Agreement to become effective upon the expiration of the then existing Rights
Agreement on May 10, 1998. Under the Rights Agreement, each right ("Right") will
entitle the holder thereof, until May 10, 2008 or the date of redemption of the
Rights, to buy one share of Common Stock of the Company at the exercise price of
$80.00, subject to adjustment. 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. At the date upon which the
rights become separate from the Company's Common Stock (the "Distribution
Date"), the Company will issue one right with each share of Common Stock that
becomes outstanding so that all shares of Common Stock will have attached
Rights. After the Distribution Date, the Company may issue Rights when it issues
Common Stock if the Board deems such issuance to be necessary or appropriate.
The Rights will separate from the Common Stock and a Distribution Date will
occur upon the occurrence of certain events specified in the Agreement,
including but not limited to, the acquisition by certain persons of at least 15%
of the beneficial ownership of the Company's Common Stock. 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 Directors 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 that the Rights become exercisable or transferable, the Rights may be
redeemed by the Company at $.01 per Right.
63
<PAGE>
Shares issued under various plans
The following table presents the number of shares issued under various
plans in 1999 and 1998, as well as the number of shares available for future
issuance at September 30, 1999.
Shares available
for issuance at
Shares issued September 30,
1999 1998 1999
-------- ------ ---------
Restricted Stock Grant Plan 56,850 114,250 731,400
Employee Stock Ownership Plan 89,435 52,473 370,963
Direct Stock Purchase Plan 694,905 531,353 273,312
Outside Directors
Stock-For-Fee Plan 1,841 2,306 40,538
United Cities Long-Term
Stock Plan 6,450 55,500 188,050
Long-Term Incentive Plan - - 1,175,000
Restricted Stock Grant Plan
The Company's Restricted Stock Grant Plan ("Plan") for management and key
employees of the Company, which became effective October 1, 1987 and was amended
and restated in November 1997, 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 restricted stock awarded. The restricted stock may
consist of previously issued shares purchased on the open market or shares
issued directly from the Company. During 1998, the Company increased the number
of shares of its common stock that may be issued under the plan by 650,000
shares. Compensation expense of $1,595,000, $1,238,000 and $437,000 was
recognized in 1999, 1998 and 1997, respectively, in connection with the vesting
of shares awarded under the Plan.
Employee Stock Ownership Plan
Prior to January 1, 1999, Atmos had an Employee Stock Ownership Plan
("ESOP") and the United Cities Division had a 401(k) savings plan. The ESOP was
amended effective January 1, 1999, as is more fully discussed in Note 8.
64
<PAGE>
Direct Stock Purchase Plan
The Company also has a Direct Stock Purchase Plan ("DSPP"). Participants in
the DSPP may have all or part of their dividends reinvested at a 3% discount
from market prices. DSPP participants may purchase additional shares of Company
common stock as often as weekly with voluntary cash payments of at least $25, up
to an annual maximum of $100,000.
Outside Directors Stock-For-Fee Plan
In November 1994, the Board adopted the Outside Directors Stock-for-Fee
Plan, which was approved by the shareholders of the Company in February 1995 and
was amended and restated in November 1997. The plan permits non-employee
directors to receive all or part of their annual retainer and meeting fees in
stock rather than in cash.
Stock-Based Compensation Plans
The Company has two stock-based compensation plans that provide for the
granting of stock options to officers, key employees and non-employee directors.
The objectives of these plans include attracting and retaining the best
personnel, providing for additional performance incentives, and promoting the
success of the Company by providing employees the opportunity to acquire common
stock.
United Cities Long-Term Stock Plan
Prior to the merger with Atmos, certain United Cities Gas Company officers
and key employees participated in the United Cities Long-Term Stock Plan
implemented in 1989. At the time of the merger on July 31, 1997, Atmos adopted
this plan by registering a total of 250,000 shares of Atmos stock to be issued
under the Long-Term Stock Plan for the United Cities Division. Under this plan,
incentive stock options, nonqualified stock options, stock appreciation rights,
restricted stock or any combination thereof may be granted to officers and key
employees of the United Cities Division. Options granted under the plan become
exercisable at a rate of 20% per year and expire 10 years after the date of
grant. During 1999, 6,450 options were exercised under the plan. At September
30, 1999, there were 80,150 options outstanding, of which 56,850 options had
vested. No incentive stock options, nonqualified stock options, stock
appreciation rights, or restricted stock have been granted under the plan since
1996.
65
<PAGE>
Long-Term Incentive Plan
On August 12, 1998, the Board of Directors approved and adopted the 1998
Long-Term Incentive Plan (the "LTIP"), which became effective October 1, 1998.
The LTIP represents a part of the Company's Total Rewards strategy, which the
Company developed as a result of a study it conducted of all employee, executive
and non-employee director compensation and benefits. The LTIP is a
comprehensive, long-term incentive compensation plan, providing for
discretionary awards of incentive stock options, non-qualified stock options,
stock appreciation rights, bonus stock, restricted stock and performance-based
stock to help attract, retain, and reward employees and non-employee directors
of the Company and its subsidiaries.
The Company is authorized to grant awards for up to a maximum of 1,500,000
shares of common stock under the LTIP, subject to certain adjustment provisions.
The option price is equal to the market price of the Company's stock at the date
of grant. The stock options expire in 10 years from the date of the grant, and
options vest annually over a service period ranging from one to three years.
During 1999, no options were exercised under the plan. At September 30, 1999,
the Company had 325,000 options outstanding under the LTIP at an exercise price
ranging from $24.41 to $25.66.
In October 1995, Statement of Financial Accounting Standards No. 123 ("SFAS
123"), "Accounting for Stock-Based Compensation," was issued. This statement
establishes a fair value-based method of accounting for employee stock options
or similar equity instruments and encourages, but does not require, all
companies to adopt that method of accounting for all of their employee stock
compensation plans. SFAS 123 allows companies to continue to measure
compensation cost for employee stock options or similar equity instruments using
the intrinsic value method of accounting described in Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). The
Company has elected to continue using the intrinsic value method as prescribed
by APB 25. Under this method no compensation cost for stock options is
recognized for stock option awards granted at or above fair market value.
Because of the limited nature of the Company's stock-based compensation
plans, the pro forma effects of applying SFAS 123 would have less than a $.01
per diluted share effect on earnings per share or approximately $84,000 for
1999.
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<PAGE>
8. Employee retirement and stock ownership plans
Defined benefit plans
Prior to January 1, 1999, the Company had four defined benefit pension
plans, covering the Western Kentucky Division employees, the Greeley Division
employees, the United Cities Division employees, and the fourth covering all
other Atmos employees. The plans provided similar benefits to all employees,
which were based upon years of service and the highest paid five consecutive
calendar years of compensation within the last 10 years of employment.
Effective January 1, 1999, the plans were merged into the Western Kentucky
Gas plan, which was amended and restated as the Atmos Pension Account Plan which
covers all employees of the Company. Opening account balances were established
for participants as of January 1, 1999 equal to the present value of their
respective accrued benefits under the pension plans as of December 31, 1998. The
Pension Account Plan credits an allocation to each participant's account at the
end of each year according to a formula based on the participant's age, service
and total pay (excluding incentive pay).
The Pension Account Plan provides for an additional annual allocation based
upon a participant's age as of January 1, 1999 for those participants who were
participants in the prior pension plans. The plan will credit this additional
allocation each year through December 31, 2008. In addition, at the end of each
year, a participant's account will be credited with interest on the employee's
prior year account balance. A special grandfather benefit also applies through
December 31, 2008, for participants who were at least age 50 as of January 1,
1999, and who were participants in one of the prior plans on December 31, 1998.
Participants are fully vested in their account balances after five years of
service and may choose to receive their account balances as a lump sum or an
annuity. The obligations shown herein reflect the changes which were effective
January 1, 1999.
The Company's funding policy is to contribute annually an amount in
accordance with the requirements of the Employee 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.
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<PAGE>
In the 1998 annual report the defined benefit plans were grouped with the
Supplemental Executive Benefits Plans. In the 1999 annual report they are
presented separately.
The Company records the accrued pension asset in deferred charges and other
assets. The following table sets forth the total for the Pension Account Plan's
funded status for 1999 and 1998:
1999 1998
-------- --------
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $218,245 $217,152
Service cost 4,232 5,256
Interest cost 14,696 15,655
Curtailments/special
termination benefits - (2,645)
Plan amendments - (14,605)
Actuarial (gain)loss (21,390) 10,638
Benefits paid (15,318) (13,206)
-------- --------
Benefit obligation at
end of year 200,465 218,245
Change in plan assets:
Fair value of plan assets
at beginning of year 286,708 259,851
Actual return on plan assets 11,108 40,063
Benefits paid (15,318) (13,206)
-------- --------
Fair value of plan assets
at end of year 282,498 286,708
-------- --------
Funded status 82,033 68,463
Unrecognized transition asset (625) (873)
Unrecognized prior service cost (9,680) (10,382)
Unrecognized net gain (48,780) (45,616)
-------- --------
Accrued pension asset $ 22,948 $ 11,592
======== ========
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<PAGE>
1999 1998 1997
----- ----- -----
Weighted average assumptions
for end of year disclosure:
Discount rate 7.5% 7.0% 7.5%
Rate of compensation increase 4.0% 4.0% 4.0%
Expected return on plan assets 10.0% 9.0% 9.0%
The plan assets consist primarily of investments in common stocks, interest
bearing securities and interests in commingled pension trust funds.
Net periodic pension cost for the Pension Account Plan for 1999, 1998 and
1997 included the following components:
1999 1998 1997
-------- -------- --------
(In thousands)
Components of net periodic
pension cost:
Service cost $ 4,232 $ 5,256 $ 6,640
Interest cost 14,696 15,655 15,301
Expected return on assets (27,846) (23,249) (19,730)
Amortization of:
Transition obligation(asset) (248) (241) (431)
Prior service cost (703) 851 921
Actuarial (gain) (1,487) (1,225) -
-------- -------- --------
Net periodic pension cost (11,356) (2,953) 2,701
Curtailment (gain)loss and
special termination benefits - (1,840) 4,758
-------- -------- --------
Total pension cost accruals $(11,356) $ (4,793) $ 7,459
======== ======== ========
Supplemental Executive Benefits Plans
The Company has a nonqualified Supplemental Executive Benefits Plan
("Supplemental Plan") which provides additional pension, disability and death
benefits to the officers and certain other employees of the Company. The
Supplemental Plan was amended and restated in August 1998. In addition, in
August 1998, the Company adopted the Performance-Based Supplemental Executive
Benefits Plan, which will cover all employees who become officers or business
unit presidents after August 12, 1998.
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<PAGE>
The Company records accrued pension cost in deferred credits and other
liabilities. The following table sets forth the total for the Supplemental
Plans' funded status for 1999 and 1998:
1999 1998
-------- --------
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $ 36,770 $ 30,796
Service cost 1,151 505
Interest cost 2,488 2,246
Plan amendments - 565
Actuarial (gain)loss 331 4,389
Benefits paid (1,915) (1,731)
-------- --------
Benefit obligation at
end of year 38,825 36,770
Change in plan assets:
Fair value of plan assets
at beginning of year - -
Employer contribution 1,915 1,731
Benefits paid (1,915) (1,731)
-------- --------
Fair value of plan assets
at end of year - -
-------- --------
Funded status (38,825) (36,770)
Unrecognized transition asset 484 580
Unrecognized prior service cost 8,837 9,858
Unrecognized net loss 6,886 6,772
-------- --------
Accrued pension cost $(22,618) $(19,560)
======== ========
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<PAGE>
1999 1998 1997
---- ---- ----
Weighted average assumptions
for end of year disclosure:
Discount rate 7.5% 7.0% 7.5%
Rate of compensation increase 4.0% 4.0% 4.0%
Expected return on plan assets 10.0% 9.0% 9.0%
Assets for the Supplemental Plans are held in the Company's rabbi trusts
(see Note 13) and consist primarily of investments in equity mutual funds. The
market value of the rabbi trusts amounted to $26.1 million at September 30,
1999. The assets in the rabbi trusts are included on the Company's balance sheet
under deferred charges and other assets and not presented above as plan assets.
The projected benefit obligation, accumulated benefit obligation, and fair
value of plan assets for the Supplemental Plans with accumulated benefit
obligations in excess of plan assets were $38.8 million, $32.8 million, and
none, respectively, as of September 30, 1999, and $36.8 million, $31.4 million,
and none, respectively, as of September 30, 1998.
Net periodic pension cost for the Supplemental Plans for 1999, 1998 and
1997 included the following components:
1999 1998 1997
------ ------ ------
(In thousands)
Components of net periodic
pension cost:
Service cost $1,151 $ 505 $ 263
Interest cost 2,488 2,246 1,932
Expected return on assets - - -
Amortization of:
Transition obligation (asset) 96 96 96
Prior service cost 1,022 810 810
Actuarial (gain) loss 216 133 390
------ ------ ------
Net periodic pension cost $4,973 $3,790 $3,491
====== ====== ======
Employee Stock Ownership Plan
Atmos sponsors an ESOP for all employees of the Company. Effective January
1, 1999 the ESOP was amended to provide for deferral of a portion of a
participant's salary of up to 21%. In addition, among other changes to the ESOP,
participants are provided with automatic matching contributions of 100% of each
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<PAGE>
participant's salary reduction up to 4% of the participant's salary, and are
provided the option of taking out loans against their ESOP accounts, subject to
certain restrictions. Each participant enters into a salary reduction agreement
with the Company pursuant to which the participant's salary is reduced by an
amount not more than 21%. 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. Matching contributions to the ESOP were expensed
as incurred and amounted to $2.4 million, $1.8 million, and $2.1 million for
1999, 1998 and 1997, 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. No discretionary
contributions were made for 1999 and 1998.
401(k) savings plan
Prior to January 1, 1999, the Company sponsored a 401(k) savings plan for
the United Cities Division employees. The Company made fixed matching
contributions of $102,000 for the three months ended December 31, 1998, $648,000
for the nine months ended September 30, 1998, and $694,000 for the year ended
December 31, 1997. In addition, a discretionary matching contribution of
$227,000 was made for 1998. The 401(k) savings plan was merged into the ESOP
effective January 1, 1999, and the United Cities Division employees subsequently
receive the same benefits as other Atmos employees.
9. Other postretirement benefits
Prior to January 1, 1999, Atmos sponsored two postretirement plans other
than pensions. Each provided health care benefits to retired employees. One
provided benefits to the United Cities Division retirees and the other provided
medical benefits to all other retired Atmos employees.
Effective January 1, 1999, the United Cities plan was merged into the Atmos
plan and began providing benefits to future retirees that are essentially the
same as provided to other Atmos employees. The obligations as of September 30,
1999 and 1998 reflect this plan change.
Substantially all of the Company's employees become eligible for these
benefits if they reach retirement age while working for the Company and attain
certain specified years of service. In addition, participant contributions are
required under the plan.
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<PAGE>
The Company records the accrued postretirement cost primarily in deferred
credits and other liabilities. The following table sets forth the total
liability currently recognized for the postretirement plan other than pensions:
1999 1998
-------- --------
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $ 64,494 $ 53,295
Service cost 2,150 1,659
Interest cost 4,360 3,809
Plan participants' contributions 763 382
Curtailments/special
termination benefits - 2,125
Plan amendments - 1,888
Actuarial (gain)loss (10,195) 6,210
Benefits paid (4,740) (4,874)
-------- --------
Benefit obligation at
end of year 56,832 64,494
Change in plan assets:
Fair value of plan assets
at beginning of year 6,380 5,614
Actual return on plan assets 377 295
Employer contribution 7,184 4,963
Plan participants' contribution 763 382
Benefits paid (4,740) (4,874)
-------- --------
Fair value of plan assets
at end of year 9,964 6,380
-------- --------
Funded status (46,868) (58,114)
Unrecognized transition
obligation 21,732 23,243
Unrecognized prior service cost 3,094 3,614
Unrecognized net (gain)loss (2,300) 8,571
-------- --------
Accrued postretirement cost $(24,342) $(22,686)
======== ========
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<PAGE>
1999 1998 1997
---- ---- ----
Weighted average assumptions
for end of year disclosure:
Discount rate 7.5% 7.0% 7.5%
Expected return on plan assets 5.3% 5.3% 5.3%
Initial trend rate 9.0% 9.0% 7.5%
Ultimate trend rate 5.0% 4.5% 5.0%
Number of years from initial to
ultimate trend 5 6 3
Net periodic postretirement cost for the combined postretirement benefit
plans for 1999, 1998 and 1997 included the following components:
1999 1998 1997
------- ------- -------
(In thousands)
Components of net periodic
postretirement cost:
Service cost $ 2,150 $ 1,659 $ 1,772
Interest cost 4,360 3,809 3,467
Expected return on assets (349) (235) (225)
Amortization of:
Transition obligation(asset) 1,511 1,862 1,994
Prior service cost 520 269 202
Actuarial (gain)loss 648 (58) 4
------- ------- -------
Net periodic postretirement
cost 8,840 7,306 7,214
Curtailment (gain)loss and
special termination benefits - 5,915 3,043
------- ------- -------
Total postretirement
cost accruals $ 8,840 $13,221 $10,257
======= ======= =======
Assumed health care cost trend rates have a significant effect on the
amounts reported for the plans. A one-percentage point change in assumed health
care cost trend rates would have the following effects on the latest actuarial
calculations:
74
<PAGE>
1-Percentage 1-Percentage
Point Increase Point Decrease
-------------- --------------
(In thousands)
Effect on total of
service and interest
cost components $ 603 $ (591)
Effect on postretirement
benefit obligation $6,361 $(5,378)
The Company is currently recovering other postretirement benefits ("OPEB")
costs through its regulated rates under SFAS No. 106 accrual accounting in
Colorado, Kansas, the majority of its Texas service area and Kentucky. It
receives rate treatment as a cost of service item for OPEB costs on the pay-as-
you-go basis in Louisiana. OPEB costs have been specifically addressed in rate
orders in each jurisdiction served by the United Cities Division or have been
included in a rate case and not disallowed. However, the Company was required to
recover the portion of the UCGC transition obligation applicable to Virginia
operations over 40 years, rather than 20 years, as in other states. Management
believes that accrual accounting in accordance with SFAS No. 106 is appropriate
and will continue to seek rate recovery of accrual-based expenses in its
ratemaking jurisdictions that have not yet approved the recovery of these
expenses.
10. Earnings per share
Basic earnings per share has been computed by dividing net income for the
period by the weighted average number of common shares outstanding during the
period. Diluted earnings per share has been computed by dividing net income for
the period by the weighted average number of common shares outstanding during
the period adjusted for restricted stock and other contingently issuable shares
of common stock. Net income for the years ended September 30, 1999, 1998 and
1997 for basic and diluted earnings per share are the same, as there were no
contingently issuable shares of stock whose issuance would have impacted net
income. A reconciliation between basic and diluted weighted average common
shares outstanding at September 30 follows:
75
<PAGE>
1999 1998 1997
------ ------ ------
(In thousands)
Weighted average common
shares - basic 30,566 29,822 29,409
Effect of dilutive securities:
Restricted stock 238 199 13
Stock options 15 10 -
------ ------ ------
Weighted average common
shares - diluted 30,819 30,031 29,422
====== ====== ======
11. Statement of cash flows supplemental disclosures
Supplemental disclosures of cash flow information for 1999, 1998 and 1997
are presented below.
1999 1998 1997
------- ------- -------
(In thousands)
Cash paid (received) for
Interest $40,446 $29,980 $25,216
Income taxes $(7,184) $25,598 $ 9,736
12. Segment Information
In fiscal 1999, the Company adopted SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information" ("SFAS No. 131"). SFAS No.
131 established standards for the way that public business enterprises report
information about operating segments in annual financial statements and requires
that those enterprises report selected information about operating segments in
interim financial reports issued to shareholders. The determination of
reportable segments under SFAS No. 131 differs from that required in previous
years; therefore, business segment information for 1998 and 1997 has been
restated to comply with the provisions of SFAS No. 131.
The Company's determination of reportable segments considers the strategic
operating units under which the Company manages 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 the summary of
significant accounting policies. All intersegment sales prices are market
based. The Company evaluates performance based on net income or loss of the
respective operating units.
76
<PAGE>
In accordance with SFAS No. 131, the Company has identified the Utility,
Propane and Energy Services segments, as described in Note 1.
Summarized financial information concerning the Company's reportable
segments is shown in the following table:
Energy
Utility Propane Services Total
---------- -------- -------- ----------
(In thousands)
As of and for the
year ended
September 30, 1999:
- -------------------
Operating revenues $ 621,211 $22,944 $53,416 $ 697,571
Intersegment revenues 3,898 - 3,477 7,375
Depreciation and
amortization 52,503 2,954 1,417 56,874
Operating income (loss) 49,000 (543) 5,782 54,239
Equity in earnings of
unconsolidated
investment - - 7,156 7,156
Interest charges, net 35,799 1,231 33 37,063
Net income (loss) 10,800 (869) 7,813 17,744
Total assets 1,152,469 16,694 77,933 1,247,096
Equity investment
in unconsolidated
investee - - 15,973 15,973
Expenditures for
additions to long-
lived assets 108,454 1,550 349 110,353
77
<PAGE>
Energy
Utility Propane Services Total
-------------- -------- -------- ---------
As of and for the (In thousands)
year ended
September 30, 1998:
- -------------------
Operating revenues 739,930 29,091 80,672 849,693
Intersegment revenues 1,485 - - 1,485
Depreciation and
amortization 43,324 2,324 1,907 47,555
Operating income 100,665 619 11,595 112,879
Equity in earnings of
unconsolidated
investment - - 3,920 3,920
Interest charges, net 33,181 897 1,501 35,579
Net income (loss) 43,332 (66) 11,999 55,265
Total assets 1,061,496 36,549 68,252 1,166,297
Equity investment
in unconsolidated
investee - - 11,914 11,914
Expenditures for
additions to long-
lived assets 125,741 8,408 840 134,989
As of and for the
year ended
September 30, 1997:
- -------------------
Operating revenues 807,428 33,194 68,389 909,011
Intersegment revenues 2,176 - - 2,176
Depreciation and
amortization 40,750 2,117 2,390 45,257
Operating income 61,213 405 4,991 66,609
Equity in earnings of
unconsolidated
investment - - 3,254 3,254
Interest charges, net 30,882 744 1,969 33,595
Net income (loss) 19,739 (90) 4,189 23,838
Total assets 1,014,263 23,110 69,083 1,106,456
Equity investment
in unconsolidated
investee - - 9,962 9,962
Expenditures for
additions to long-
lived assets 117,496 3,271 1,545 122,312
78
<PAGE>
The following table presents a reconciliation of the operating revenues to
total consolidated revenues for the years ended September 30, 1999, 1998 and
1997.
1999 1998 1997
-------- -------- --------
(In thousands)
Total revenues for
reportable segments $697,571 $849,693 $909,011
Elimination of
intersegment revenues (7,375) (1,485) (2,176)
-------- -------- --------
Total operating revenues $690,196 $848,208 $906,835
======== ======== ========
A reconciliation of total assets for the reportable segments to total
consolidated assets for September 30, 1999, 1998 and 1997 is presented below.
1999 1998 1997
---------- ---------- ----------
(In thousands)
Total assets for
reportable segments $1,247,096 $1,166,297 $1,106,456
Elimination of
intercompany receivables (16,559) (24,907) (18,145)
---------- ---------- ----------
Total consolidated
assets $1,230,537 $1,141,390 $1,088,311
========== ========== ==========
The following table summarizes the Company's revenues by products and
services for the year ended September 30.
79
<PAGE>
1999 1998 1997
---------- ---------- ----------
(In thousands)
Gas sales revenues:
Residential $ 349,691 $ 410,538 $ 452,864
Commercial 144,836 184,046 193,302
Public authority
and other 22,330 20,504 23,898
Industrial 73,194 91,972 109,241
---------- ---------- ----------
Total gas sales
revenues 590,051 707,060 779,305
Transportation revenues 23,035 23,883 19,804
Other gas revenues 4,227 7,502 6,143
---------- ---------- ----------
Total utility
revenues 617,313 738,445 805,252
Propane revenues 22,944 29,091 33,194
Energy services revenues 49,939 80,672 68,389
---------- ---------- ----------
Total operating
revenues $ 690,196 $ 848,208 $ 906,835
========== ========== ==========
13. Marketable Securities
In accordance with Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," all
marketable securities are classified as available-for-sale and are reported at
market value with unrealized gains and losses shown as a component of
shareholders' equity labeled "unrealized holding gains (losses)." All
marketable securities are held in rabbi trusts for the Supplemental Executive
Benefit Plan ("SEBP").
80
<PAGE>
The cost, unrealized holding gain (loss), and the market value of the
marketable securities are:
Unrealized
Holding Market
Cost Gain (Loss) Value
------- ----------- -------
(In thousands)
As of September 30, 1999
Available-for-sale securities:
Domestic equity mutual funds $22,265 $1,041 $23,306
Foreign equity mutual funds 2,359 399 2,758
------- ------ -------
$24,624 $1,440 $26,064
======= ====== =======
14. Leases
The Company has entered into non-cancelable operating leases for office and
warehouse space used in its operations. The remaining lease terms range from
one to 20 years and generally provide for the payment of taxes, insurance and
maintenance by the lessee. The Company has also entered into capital leases for
division offices and operating facilities. Property, plant and equipment
included amounts for capital leases of $4.6 million and $4.1 million at
September 30, 1999 and 1998, respectively. Accumulated depreciation for these
capital leases totaled $1.2 million and $.9 million at September 30, 1999 and
1998, respectively.
81
<PAGE>
The related future minimum lease payments at September 30, 1999 were as
follows:
Capital Operating
leases leases
-------- ---------
(In thousands)
2000 $ 735 $10,413
2001 735 10,010
2002 735 9,811
2003 735 9,262
2004 735 9,091
Thereafter 3,384 48,211
------- -------
Total minimum lease payments 7,059 $96,798
=======
Less amount representing interest (3,671)
-------
Present value of net minimum
lease payments $ 3,388
=======
Consolidated lease and rental expense amounted to $10.6 million, $9.2
million and $10.5 million for fiscal 1999, 1998 and 1997, respectively. Rents
for the regulated business are expensed and the Company receives rate treatment
as a cost of service on a pay-as-you-go basis.
15. Related Party Transactions
Included in purchased gas cost were purchases from WMLLC of $117.4 million,
$124.7 million and $103.0 million in 1999, 1998 and 1997, respectively. Volumes
purchased were 50.9 billion cubic feet ("Bcf"), 53.4 Bcf and 38.6 Bcf in 1999,
1998 and 1997, respectively. These purchases were made in a competitive open
bidding process and reflect market prices. Average prices per thousand cubic
feet ("Mcf") for gas purchased from WMLLC were $2.31, $2.33 and $2.67 in 1999,
1998 and 1997, respectively.
16. Subsequent Event
Subsequent to September 30, 1999, the Company entered into a definitive
agreement with Southwestern Energy Company ("Southwestern") to acquire the
Missouri natural gas distribution assets of Associated Natural Gas, a division
of Arkansas Western Gas, which is a wholly-owned subsidiary of Southwestern.
Under the terms of the agreement, the Company will purchase the Missouri gas
system for $32.0 million in cash plus working capital adjustments. This
transaction, which will
82
<PAGE>
add approximately 48,000 customers, is expected to be completed by mid-year
2000, subject to approvals by the Missouri Public Service Commission and the
Federal Energy Regulatory Commission.
17. Selected 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. The Company's natural gas and propane distribution
businesses are seasonal due to weather conditions in the Company's service
areas. For further information on its effects on quarterly results, please see
the "Seasonality" discussion included in the "Management's Discussion and
Analysis of Financial Condition and Results of Operations" section herein.
<TABLE>
<CAPTION>
Fiscal year 1999
-------------------------------------------------------
Quarter ended
December 31, March 31, June 30, September 30,
-------------------------------------------------------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
Operating revenues $210,227 $261,426 $109,590 $108,953
Gross profit 91,208 112,395 53,376 42,815
Operating
income (loss) 31,688 50,843 412 (28,704)
Net income (loss) 15,380 28,795 (5,295) (21,136)
Net income (loss)
per share .50 .94 (.17) (.68)
<CAPTION>
Fiscal year 1998
-------------------------------------------------------
Quarter ended
December 31, March 31, June 30, September 30,
-------------------------------------------------------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
Operating revenues $295,331 $288,550 $137,311 $127,016
Gross profit 99,601 123,971 57,366 50,898
Operating
income (loss) 40,952 67,203 7,882 (3,158)
Net income (loss) 20,122 37,398 1,676 (3,931)
Net income (loss)
per share .68 1.25 .06 (.13)
</TABLE>
83
<PAGE>
Exhibit 21
SUBSIDIARIES OF ATMOS ENERGY CORPORATION
Name State of Percent of
Incorporation Stock
ATMOS ENERGY SERVICES, INC. Delaware 100%
GREELEY ENERGY SERVICES, INC.
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Delaware 100%
TRANS LOUISIANA ENERGY SERVICES, INC.
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Delaware 100%
UNITED CITIES ENERGY SERVICES, INC.
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Delaware 100%
WKG ENERGY SERVICES, INC.
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Delaware 100%
TRANS LOUISIANA INDUSTRIAL GAS
COMPANY, INC. (a wholly-owned
subsidiary of Atmos Energy Services,
Inc.) Louisiana 100%
EGASCO, LLC
(a Texas Limited Liability Company)
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Texas 100%
ENERTRUST, INC.
(a wholly-owned subsidiary of
Atmos Energy Services, Inc.) Delaware 100%
ENERMART ENERGY SERVICES TRUST
(a Pennsylvania Business Trust)
(wholly-owned by Enertrust, Inc.) Pennsylvania 100%
ENERGAS ENERGY SERVICES TRUST
(a Pennsylvania Business Trust)
(wholly-owned by Enertrust, Inc.) Pennsylvania 100%
<PAGE>
Name State of Percent of
Incorporation Stock
UNITED CITIES PROPANE GAS, INC. Tennessee 100%
ATMOS ENERGY MARKETING, LLC
(a Delaware Limited Liability
Company) Delaware 100%
ATMOS LEASING, INC. Georgia 100%
ATMOS NON-REGULATED SHARED
SERVICES, INC. Delaware 100%
ATMOS STORAGE, INC. Delaware 100%
UCG STORAGE, INC.
(a wholly-owned subsidiary of
Atmos Storage, Inc.) Delaware 100%
WKG STORAGE, INC.
(a wholly-owned subsidiary of
Atmos Storage, Inc.) Delaware 100%
ATMOS EXPLORTATION AND PRODUCTION,
INC. (a wholly-owned subsidiary of
Atmos Storage, Inc.) Delaware 100%
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITOR
We consent to the incorporation by reference in the Registration Statements
(Form S-3, No. 33-37869; Form S-3 D/A, No. 33-70212; Form S-3, No. 33-58220;
Form S-3, No. 33-56915; Form S-3/A, No. 333-03339; Form S-3/A, No. 333-32475;
Form S-3/A, No. 333-50477; Form S-4, No. 333-13429; Form S-8, No. 33-68852; Form
S-8, No. 33-57687; Form S-8, No. 33-57695; Form S-8, No. 333-32343; and Form
S-8, No. 333-46337, Form S-8, No. 333-73143; and Form S-8, No. 333-73145) of
Atmos Energy Corporation and in the related Prospectuses of our report dated
November 9, 1999, with respect to the consolidated financial statements of Atmos
Energy Corporation incorporated by reference in this Annual Report (Form 10-K)
for the year ended September 30, 1999.
Our audits also included the financial statement schedule of Atmos Energy
Corporation listed in Item 14(a). This schedule is the responsibility of the
Company's management. Our responsibility is to express an opinion based on our
audits. In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
ERNST & YOUNG LLP
Dallas, Texas
December 14, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF ATMOS ENERGY CORPORATION FOR THE YEAR ENDED
SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 965,782
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 135,153
<TOTAL-DEFERRED-CHARGES> 129,602
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,230,537
<COMMON> 156
<CAPITAL-SURPLUS-PAID-IN> 293,359
<RETAINED-EARNINGS> 84,148
<TOTAL-COMMON-STOCKHOLDERS-EQ> 377,663
0
0
<LONG-TERM-DEBT-NET> 377,483
<SHORT-TERM-NOTES> 15,650
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 152,654
<LONG-TERM-DEBT-CURRENT-PORT> 17,848
0
<CAPITAL-LEASE-OBLIGATIONS> 3,035
<LEASES-CURRENT> 353
<OTHER-ITEMS-CAPITAL-AND-LIAB> 285,851
<TOT-CAPITALIZATION-AND-LIAB> 1,230,537
<GROSS-OPERATING-REVENUE> 690,196
<INCOME-TAX-EXPENSE> 9,555
<OTHER-OPERATING-EXPENSES> 635,957
<TOTAL-OPERATING-EXPENSES> 645,512
<OPERATING-INCOME-LOSS> 44,684
<OTHER-INCOME-NET> 10,123
<INCOME-BEFORE-INTEREST-EXPEN> 54,807
<TOTAL-INTEREST-EXPENSE> 37,063
<NET-INCOME> 17,744
0
<EARNINGS-AVAILABLE-FOR-COMM> 17,744
<COMMON-STOCK-DIVIDENDS> 33,882
<TOTAL-INTEREST-ON-BONDS> 11,807
<CASH-FLOW-OPERATIONS> 84,698
<EPS-BASIC> 0.58
<EPS-DILUTED> 0.58
</TABLE>
