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 (Fee Required)
For the fiscal year ended September 30, 1994 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (No Fee Required)
For the transition period from __________ to ____________
Commission File Number 1-10042
ATMOS ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 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:
(214) 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 ___.
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]<PAGE>
The aggregate market value of the voting stock held by non-
affiliates of the registrant was $237,127,039 as of December 1,
1994. On December 1, 1994, the registrant had 15,347,251 shares
of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of registrant's definitive proxy statement filed
for the annual meeting of shareholders on February 8, 1995 are
incorporated by reference into Part III.<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. Immediate-
ly following the transfer of such business, which had been opera-
ted by Pioneer and its predecessors since 1906, Pioneer distrib-
uted 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.
The Company distributes and sells natural gas to
residential, commercial, industrial, agricultural, and other
customers in 413 cities, towns, and communities in parts of
Texas, Louisiana, Kentucky, Colorado, Kansas, and Missouri. The
Company also transports gas for others through parts of its
distribution system. The Company is also helping promote the
development of a market for natural gas as a clean burning
vehicular fuel by opening four public refueling facilities in its
service areas.
The Company's Texas distribution system is operated through
its Energas Company division (the "Energas Division") and is
located in the western part of Texas covering an area having a
population of approximately 950,000 people. The economy of the
area is based primarily on oil and gas production and agricul-
ture. The principal cities served by the Energas Division
include Amarillo, Lubbock, Midland, and Odessa. At September 30,
1994, the Company had 309,496 gas 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 is located in Louisiana covering 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, 1994, the Company had 70,361 gas 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 Paducah. At September 30, 1994, the Company had
164,828 gas meters in service in Kentucky.
In December 1993, the Company acquired Greeley Gas Company
("GGC") of Denver, Colorado in a merger accounted for as a pool-
1<PAGE>
ing of interests, and accordingly, all amounts included herein
have been restated to include GGC's operating results. Since the
merger, the business of GGC has been operated through the
Company's Greeley Gas Company division (the "Greeley Gas
Division"). It serves customers in areas of Colorado, Kansas,
and Missouri having a combined population of approximately
228,000 people. The economies of the areas served are based on
oil and gas production, agriculture and resort business in
Colorado. The principal cities served include Greeley, Durango
and Lamar, Colorado and Bonner Springs, Herington and Ulysses,
Kansas. At September 30, 1994 the Greeley Gas Division had
104,634 meters in service.
The natural gas distribution industry is subject to numerous
special factors, many of which affect the Company from time to
time. These include (i) 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 in local gas distribution service areas; (iii)
competition from alternate fuels; (iv) competition with other gas
sources for industrial customers, including bypass of 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.
ACQUISITIONS
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, and Greeley Gas Company ("GGC") in December 1993.
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 GGC merger, see Note 2 of notes to consolidated
financial statements, and Management's Discussion and Analysis.
FIVE-YEAR OPERATING STATISTICS
Certain information with respect to the Company's natural
gas operations for the past five years is shown on the following
page.
2 <PAGE>
<TABLE>
<CAPTION>
Year ended September 30,
----------------------------------------------------------
1994 1993 1992 1991 1990
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
NUMBER OF ACCOUNTS, at end of year
Residential 549,129 539,309 534,762 529,498 523,029
Commercial 55,027 54,275 55,562 54,703 53,992
Industrial (including agricultural) 8,781 8,924 9,331 9,793 10,045
Public authority and other 3,351 3,267 1,745 1,788 1,677
------- ------- ------- ------- -------
Total 616,288 605,775 601,400 595,782 588,743
======= ======= ======= ======= =======
METERS IN SERVICE, at end of year 649,319 636,159 630,365 619,111 613,542
======= ======= ======= ======= =======
HEATING DEGREE DAYS, system average (1)
Actual 3,953 4,046 3,676 3,583 3,751
Normal 3,983 3,983 3,983 3,983 3,983
Percent of normal 99% 102% 92% 90% 94%
SALES VOLUMES - MMcf (2)
Residential 51,209 51,763 48,223 47,484 48,635
Commercial 21,134 21,872 20,675 20,778 21,256
Industrial (including agricultural) 38,502 31,367 27,489 29,788 33,018
Public authority and other 5,242 4,403 3,333 3,385 3,515
------- ------- ------- ------- -------
Total 116,087 109,405 99,720 101,435 106,424
TRANSPORTATION VOLUMES - MMcf (2) 35,308 39,782 32,203 35,201 32,178
------- ------- ------- ------- -------
TOTAL VOLUMES HANDLED - MMcf (2) 151,395 149,187 131,923 136,636 138,602
======= ======= ======= ======= =======
OPERATING REVENUES (000's)
Gas Revenues
Residential $245,931 $237,914 $211,767 $202,486 $199,818
Commercial 92,507 91,250 82,311 81,414 81,061
Industrial (including agricultural) 119,722 92,455 77,218 81,746 94,653
Public authority and other 22,463 18,315 13,232 13,290 13,115
-------- -------- -------- -------- --------
Total gas revenues 480,623 439,934 384,528 378,936 388,647
Transportation Revenues 14,118 15,013 13,674 16,348 16,919
Other Revenue 5,067 4,694 5,151 4,383 4,409
-------- -------- -------- -------- --------
Total operating revenues $499,808 $459,641 $403,353 $399,667 $409,975
======== ======== ======== ======== ========
AVERAGE SALES PRICE/Mcf
Residential $4.80 $4.60 $4.39 $4.26 $4.11
Commercial 4.38 4.17 3.98 3.92 3.81
Industrial (including agricultural) 3.11 2.95 2.81 2.74 2.87
Public authority and other 4.29 4.16 3.97 3.93 3.73
Total 4.14 4.02 3.86 3.74 3.65
AVERAGE COST OF GAS/Mcf SOLD 2.86 2.71 2.58 2.58 2.57
<FN>
See footnotes on page 4.
</TABLE>
4 <PAGE>
<TABLE>
SALES AND STATISTICAL DATA BY STATE - 1994
<CAPTION>
Year ended September 30, 1994
---------------------------------------------------------------
Texas Louisiana Kentucky Colorado Kansas Mo. Total
------- ------ ------- ------ ------ --- -------
<S> <C> <C> <C> <C> <C> <C> <C>
METERS IN SERVICE, at end of year
Residential 263,330 64,401 146,384 67,062 23,692 546 565,415
Commercial 24,899 4,944 16,653 9,594 3,228 71 59,389
Industrial (including agricultural) 18,749 108 268 108 333 - 19,566
Public authority and other 2,518 908 1,523 - - - 4,949
------- ------ ------- ------ ------ --- -------
Total 309,496 70,361 164,828 76,764 27,253 617 649,319
======= ====== ======= ====== ====== === =======
HEATING DEGREE DAYS, system average <F1>
Actual 3,561 1,922 4,342 6,116 5,108 4,990 3,953
Normal 3,528 1,760 4,376 6,556 5,158 5,028 3,983
Percent of normal 101% 109% 99% 93% 99% 99% 99%
SALES VOLUMES <F2>
Residential 24,276 3,604 13,776 7,041 2,464 48 51,209
Commercial 7,933 1,260 5,820 4,943 1,167 11 21,134
Industrial (including agricultural) 25,791 1,606 8,766 734 1,605 - 38,502
Public authority and other 2,714 885 1,643 - - - 5,242
------ ----- ------ ----- ----- -- ------
Total 60,714 7,355 30,005 12,718 5,236 59 116,087
TRANSPORTATION VOLUMES <F2> 14,179 500 17,498 3,071 60 - 35,308
------ ----- ------ ------ ----- -- -------
TOTAL VOLUMES HANDLED <F2> 74,893 7,855 47,503 15,789 5,296 59 151,395
====== ===== ====== ====== ===== == =======
OTHER STATISTICS
Operating revenues (000's) $234,628 $43,374 $143,508 $55,010 $22,880 $408 $499,808
Gross plant (000's) $221,516 $86,771 $127,169 $70,852 $36,819 $565 $543,692
Net plant (000's) $119,616 $66,220 $79,410 $40,355 $21,446 $360 $327,407
Miles of pipe 13,007 1,815 3,425 2,352 1,295 33 21,927
Employees <F3> 859 166 387 221 76 - 1,709
Communities served 92 36 163 62 58 2 413
Estimated population in service area 950,000 250,000 680,000 160,000 66,000 2,000 2,108,000
Estimated square miles in service
area 30,000 7,000 12,000 1,050 580 20 50,650
Vehicles in fleet 446 137 268 154 52 - 1,057
Franchises 71 58 62 36 42 2 271
<FN>
<F1> 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 coldness of weather experienced and to compare relative
temperatures between one geographic area and another. Degree day
information for the small service area in Missouri is not available
for 1993 and would not impact the total Company average.
5 <PAGE>
<F2> Volumes are reported as metered in million cubic feet ("MMcf").
<F3> The Texas column includes 224 and 219 employees in the Dallas general
office in 1994 and 1993, respectively.
</TABLE>
6 <PAGE>
<TABLE>
SALES AND STATISTICAL DATA BY STATE - 1993
<CAPTION>
Year ended September 30, 1993
---------------------------------------------------------------
Texas Louisiana Kentucky Colorado Kansas Mo. Total
------- ------ ------- ------ ------ --- -------
NUMBER OF ACCOUNTS, at end of year
<S> <C> <C> <C> <C> <C> <C> <C>
Residential 256,487 60,042 138,443 61,110 22,740 487 539,309
Commercial 22,974 4,560 15,229 8,402 3,048 62 54,275
Industrial (including agricultural) 8,094 93 312 90 335 - 8,924
Public authority and other 1,024 768 1,475 - - - 3,267
------- ------ ------- ------ ------ --- -------
Total 288,579 65,463 155,459 69,602 26,123 549 605,775
======= ====== ======= ====== ====== === =======
METERS IN SERVICE 309,270 68,644 161,971 69,602 26,123 549 636,159
======= ====== ======= ====== ====== === =======
HEATING DEGREE DAYS, system average (1)
Actual 3,661 1,812 4,136 6,955 5,376 N/A 4,046
Normal 3,528 1,760 4,376 6,556 5,158 N/A 3,983
Percent of normal 104% 103% 95% 106% 104% N/A 102%
SALES VOLUMES (2)
Residential 25,372 3,531 13,314 6,961 2,536 49 51,763
Commercial 8,133 1,230 6,110 5,094 1,294 11 21,872
Industrial (including agricultural) 22,352 1,211 5,708 679 1,417 - 31,367
Public authority and other 2,757 850 796 - - - 4,403
------ ----- ------ ----- ----- -- ------
Total 58,614 6,822 25,928 12,734 5,247 60 109,405
TRANSPORTATION VOLUMES (2) 17,645 354 18,348 3,092 343 - 39,782
------ ----- ------ ------ ----- -- -------
TOTAL VOLUMES HANDLED (2) 76,259 7,176 44,276 15,826 5,590 60 149,187
====== ===== ====== ====== ===== == =======
OTHER STATISTICS
Operating revenues (000's) $224,264 $38,954 $125,277 $49,372 $21,356 $418 $459,641
Gross plant (000's) $201,501 $81,848 $116,055 $70,100 $31,579 $429 $501,512
Net plant (000's) $102,684 $62,443 $75,382 $40,663 $17,849 $254 $299,275
Miles of pipe 12,878 1,785 3,364 2,251 1,149 33 21,460
Employees (3) 843 170 390 260 93 - 1,756
Communities served 92 36 163 62 58 2 413
Estimated population in service area 950,000 250,000 680,000 160,000 66,000 2,000 2,108,000
Estimated square miles in service
area 30,000 7,000 12,000 1,050 580 20 50,650
Vehicles in fleet 433 127 265 156 52 - 1,033
Franchises 71 57 64 34 39 2 267
<FN>
See footnotes on page 4.
</TABLE>
7 <PAGE>
8 <PAGE>
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 and Kansas
who utilize natural gas to operate irrigation equipment. The Company's
management believes that the Company has lessened its sensitivity to
weather risk by diversifying its operations into geographic areas having
different weather patterns.
The Company's revenues are affected by the cost of natural gas,
economic conditions in the areas that the Company serves, and weather
conditions. 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, excess supply in the natural gas market has led to a
decline in natural gas prices and an increase in the number of competing
marketers of natural gas to large volume users. In order to compete with
these marketers, the Company's three gas marketing subsidiaries purchase
gas for resale to various large volume customers.
In certain instances, industrial customers purchase gas directly from
other marketers or from one of the Company's gas marketing subsidiaries,
and the Company transports such gas through its distribution systems to the
customers' facilities for a fee. Transportation of customer-owned gas that
otherwise would have been sold by the Company reduces the Company's
operating revenues and corresponding purchased gas cost. However, the
transportation fees received by the Company may offset the loss of gross
profit that would have been realized had the Company sold such gas to such
customers.
The Company's distribution systems have experienced aggregate peak day
deliveries of approximately 1 billion cubic feet ("Bcf") per day. The
Company has the ability to curtail deliveries to certain interruptible
customers under the terms of 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
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 and January 1994. GGC has not
curtailed deliveries to its sales customers since prior to 1980.
GAS SUPPLY
The principal gas suppliers to the Company in 1994, 1993 and 1992
included Westar Transmission Company ("Westar"), an affiliate of KNEnergy;
Anthem Energy Company, L.P. ("Anthem") an affiliate of KNEnergy; Mesa
9<PAGE>
Operating Company ("Mesa"); Louisiana Intrastate Gas Corporation ("LIG"),
an affiliate of Equitable Resources Inc.; Tennessee Gas Pipeline Company
("Tennessee Gas"), an affiliate of Tenneco, Inc.; Texas Gas Transmission
Corporation ("Texas Gas"), an affiliate of Transco; Texaco Gas Marketing;
Union Pacific Fuels; Vastar, an affiliate of ARCO; Associated Natural Gas,
Inc. ("ANGI"); and Rangeline Corporation ("Rangeline"), an affiliate of
Astra Resources. The prices paid by the Company for natural gas delivered
to it are set by contracts with gas suppliers and/or ratemaking proceedings
before regulatory authorities. Charges for gas costs are passed through to
the Company's customers under approved or negotiated tariffs or pursuant to
contract.
10 <PAGE>
The following table sets forth volumes purchased from the Company's
principal gas suppliers for the years ended September 30, 1994, 1993, and
1992.
Volumes
purchased
(MMcf as metered)
1994:
Westar and Anthem 47,842
Mesa 9,926
LIG 4,254
Texaco Gas Marketing 5,453
Union Pacific Fuels 5,825
Vastar 6,881
Associated Natural Gas, Inc. 3,283
Rangeline Corporation 2,210
1993:
Westar and Anthem 45,031
Mesa 10,659
LIG 4,490
Tennessee Gas 2,575
Texas Gas 10,329
Associated Natural Gas, Inc. 3,291
Rangeline Corporation 1,946
1992:
Westar and Anthem 38,539
Mesa 9,823
LIG 5,961
Tennessee Gas 2,594
Texas Gas 16,131
Associated Natural Gas, Inc. 3,049
Rangeline Corporation 1,295
Westar and Anthem supply natural gas to most of the Energas Division
under multiple contracts. The Westar contract expires in 1998. The Anthem
contracts are renegotiated annually. Westar purchases gas from various
pipeline companies and natural gas processing plants and at the wellhead.
Westar's gas price to the Company is subject to an annual adjustment in
accordance with the existing contract. Under the Westar contract, the
Company has the right annually to elect to buy up to 20% of its monthly re-
quirements for its Energas Division from other suppliers.
The principal gas supply for the Company's Amarillo, Texas
distribution system is furnished by Mesa under a long-term contract that
expires upon the depletion of the field from which the gas is produced.
Mesa owns the gas rights in certain specified acreage in the West Panhandle
field. Pursuant to a contract between Colorado Interstate Gas Company
("CIG") and Mesa, CIG is obligated to deliver to Mesa the volumes of gas
required for sale to customers in Amarillo and its environs, subject to
certain contractual volume limitations, so long as the gas reserves from
the West Panhandle field are commercially producible. In June 1992, the
Company renegotiated the pricing provisions of its primary gas supply
11<PAGE>
contract for the Amarillo, Texas distribution system. The contract calls
for a pricing formula which determines the prices the Company pays each
year during the five year period that began January 1, 1993. The contract
also provides a mechanism for price redetermination each two year period
thereafter beginning January 1, 1998.
On October 28, 1991, the Company and LIG entered into new agreements
which were approved by the Louisiana Public Service Commission ("Louisiana
Commission") on November 26, 1991, and became effective June 1, 1992.
These agreements provide continued supply by LIG for most of the Trans La
Division's gas requirements for a term of ten years (but subject to
cancellation by either party after five years). The agreements provide for
market sensitive pricing and allow the Company to purchase certain volumes
of gas from other suppliers. Under the contract, the Trans La Division has
the right to purchase a portion of its requirements from suppliers other
than LIG at market sensitive prices. At the end of the second contract
year, the Trans La Division had the right to increase its purchases from
others up to approximately 45% of its requirements which right was
exercised by Trans La. LIG is required to provide standby service to back
up the purchases from the other suppliers.
The Company purchases some gas supplies for resale to certain of its
Louisiana industrial customers from suppliers other than LIG. The
Company's Louisiana industrial sales subsidiary, Trans Louisiana Industrial
Gas Company, Inc., has entered into supply contracts at market sensitive
prices with Enron Gas Services, Inc. for the major portion of its
requirements, with the remainder being purchased under 30-day contracts
from other suppliers. Gas provided by these suppliers is transported by
LIG with delivery into the Trans La Division's system.
The Western Kentucky Division transports its natural gas requirements
through firm transportation agreements with Texas Gas and Tennessee Gas
with the exception of a small percentage of the requirements being
purchased directly from intrastate producers. The Western Kentucky
Division purchases its supply under staggered term contracts from major
producers and marketers including Texaco, Union Pacific, Vastar, Associated
Natural, Hadson and Chevron.
The Company's distribution system in the Western Kentucky Division
includes six underground storage facilities, which are used to help meet
customer requirements during peak demand periods and to reduce the need to
contract additional pipeline volumes to meet such peak demand periods. See
"Item 2. Properties" for further information regarding the underground
storage facilities. The Company has also bought gas in underground storage
facilities of Tennessee Gas in Louisiana and Kentucky under FERC Order 636.
The Greeley Gas Division purchases or transports approximately 72% of
its natural gas requirements on eight pipelines. Five of these are
regulated by the FERC and the remaining three are state regulated. The
FERC pipelines are Colorado Interstate Gas Company, Williams Natural Gas
Company, KNEnergy, Northwest Pipeline Corporation, and NorAm. The state
regulated pipelines are Public Service Company of Colorado, KPL Gas Service
Company and Kansas Pipeline Partnership in Kansas. Approximately 28% of
the Divisions's gas supply is purchased from local sources. Several of the
operating areas are in or adjacent to natural gas producing fields.
12<PAGE>
Each of the Greeley Gas Division's operating areas is connected to one
of the pipeline suppliers so that gas prices can be managed by using any of
three sources: pipeline purchase, pipeline transport, or local purchases.
Associated Natural Gas, Inc. is the main supplier to the Greeley Gas
Division's largest district, the Greeley District. There are two contracts
with ANGI - one contract for fixed-price base load gas put directly into
the Greeley Gas Division distribution system from natural gas processing
plants, and one contract for monthly market-sensitive spot purchases.
Rangeline is the principal gas supplier for the Kansas and Missouri
districts. Gas is transported through three different pipeline systems
(Williams Natural Gas, KPL, and NorAm). The contract with Rangeline for
gas transported through Williams Natural Gas expires in October 1996, the
contract for the KPL transported gas expires in August 1996, and the
contract for the NorAm transported gas is monthly. The contracts with
Rangeline provide for market-sensitive pricing.
The Company has not experienced curtailment in its Texas distribution
system since it began independent operations in 1983, in its Louisiana
system since its acquisition, or in Colorado, Kansas or Missouri since
prior to 1980. A large proportion of the Company's sales are made to high
priority residential and commercial consumers; therefore, any curtailment
of supply for these customers is unlikely. However, the distribution
system in Kentucky has occasionally interrupted contractually interruptible
industrial and large volume commercial customers. The most recent
interruption for these Kentucky customers was in January 1994.
REGULATION AND RATES
Regulation. 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 ("Railroad Commission") 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 industrial 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.
The operations of the Trans La Division are under the jurisdiction of
the Louisiana Public Service Commission, which regulates utility services,
13<PAGE>
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.
The operations of the Western Kentucky Division are under the
jurisdiction of the Kentucky Public Service Commission, which regulates
utility services, rates, issuances 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 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.
The Greeley Gas Division is subject to the regulatory authority of 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 Gas
Division's wholesale gas suppliers are regulated by various federal and
state commissions.
The Company is 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.
Rates. Approximately 87% of the Company's revenues in fiscal 1994 was
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
six states in which the Company operates. Generally, the Company applies
for a specific rate structure based upon requirements of the regulatory
authority. 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 a reasonable return on
invested capital. The Company has not always agreed with its regulators'
decisions on its rate filings and has pursued the appeal and rehearing
14<PAGE>
procedures in Texas in 1985 and 1992 and in Kentucky in 1991. The Company
also continually reviews its rates in all of its jurisdictions.
Substantially all of the sales rates charged by the Company to its
customers fluctuate with the cost of gas purchased by the Company. Base
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 following table sets forth the major rate requests made by the
Company and the action taken on such requests:
Amount Amount
Jurisdiction Effective Date Requested Received
------------ ---------------- --------- --------
Texas
West Texas
System (a) November 1, 1984 $8,915,000 $5,000,000
September 9, 1991 5,987,000 4,600,000
November 18, 1994 2,581,000 1,502,000 (a)
Amarillo December 11, 1985 4,850,000 3,400,000
November 25, 1992 4,398,000 2,130,000
Louisiana April 1, 1987 5,195,000 3,610,000
September 3, 1992 3,409,000 974,000 (b,c)
March 1, 1993 (c) 730,000 (c)
March 1, 1994 (c) 1,058,000 (c)
Kentucky May 29, 1991 8,973,000 3,632,000
Colorado May 9, 1985 1,651,000 1,575,000
November 6, 1990 2,677,000 1,405,000
May 1, 1994 4,527,000 3,246,000
Kansas July 28, 1983 1,214,000 1,003,000
November 14, 1986 934,000 844,000
October 22, 1990 2,485,000 1,376,000
January 6, 1992 1,495,000 505,000
December 1, 1993 2,604,000 2,088,000
Missouri June 1, 1990 N/A (d) 49,000
- ---------------------
(a) Excludes the City of Amarillo and certain smaller distribution
systems. The $1,502,000 annual increase received in November 1994
applies to customers inside the city limits of the cities in this
service area. The portion of the rate request for rural customers,
who represent about 10% of the customers in this service area, is
pending before the Railroad Commission of Texas.
(b) The September 1992 rate order provided an additional $800,000 for
franchise tax expense.
(c) The September 1992 rate order also approved a Rate Stabilization
Clause ("RSC") for three years which provides for an annual adjustment
15<PAGE>
of rates to reflect changes in expenses and investment. The RSC
provides the Company the opportunity to earn a return on common equity
between 11.75% and 12.25%.
(d) The rate request procedures in Missouri that are applicable to the
Greeley Gas Division do not require the filing of a formal rate
request. The rate increase received is established by the Missouri
Public Service Commission on the basis of the Greeley Gas Division's
responses to various data requests from the Commission. Consequently,
the Greeley Gas Division did not specify a requested rate increase
amount.
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.
Beginning in 1985, changes in the federal regulatory environment
through FERC orders and conditions related to markets and gas supply in the
United States have brought increased competition into the natural gas
industry. In 1992, the FERC issued Order 636 and related clarifying
orders. These orders provided for further restructuring of interstate
pipeline services and are intended to completely unbundle pipeline trans-
portation and sales functions. The FERC orders make gas transportation
more accessible to users of large quantities of gas and also reduce
procedural obstacles allowing such users to bypass local distribution
companies, such as the Company, to purchase gas from other suppliers, and
to secure transportation directly from pipeline companies. The Company has
felt the impact of the competitiveness in the large volume market in some
areas resulting from these changes and has dealt with this by seeking
regulatory approval for competitive pricing on a case by case basis. The
FERC policies apply only to interstate pipelines and have not had a direct
impact upon the Company's operations which are primarily supplied by
intrastate pipelines.
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 late 1991, the Company opened four public retail facilities for the
sale of compressed natural gas ("CNG") for vehicular use. The facilities
are located at existing local gasoline stations. Prior to that time, the
Company provided CNG for vehicular use only in limited situations (such as
for school buses in certain school districts and for the fleet vehicles of
certain businesses). With the opening of these public refueling stations
the Company began competing against gasoline for vehicular fuel sales.
16<PAGE>
Employees
At September 30, 1994, the Company employed 1,709 persons. See page 4
for number of employees by state.
ITEM 2. PROPERTIES
The Company owns an aggregate of 21,927 miles of underground pipelines
throughout its gas distribution systems. These pipelines are located on
easements or rights-of-way granted to the Company, which generally provide
for perpetual use. The Company maintains its pipelines through a program
of continuous inspection and repair and believes that the pipeline system
is in good condition. The Company also owns or operates six underground
gas storage facilities in Kentucky that have a total storage capacity of
approximately 11.7 Bcf. However, approximately 6.5 Bcf of gas in the
storage facilities must be retained as cushion gas. The maximum daily
delivery capability of the storage facilities is approximately 112 MMcf.
Substantially all of the Company's properties in its Greeley Gas
Division with a book value of approximately $59.2 million are subject to a
lien under First Mortgage Bonds assumed by the Company in the acquisition
of GGC. At September 30, 1994, the lien secured approximately $17.0
million of outstanding 9.4% Series J First Mortgage Bonds due May 1, 2021.
The Company leases its executive and administrative headquarters in
Dallas, Texas under leases that expire in 1997. The Company also maintains
field offices throughout its distribution system, substantially all of
which are located in leased premises.
The Company holds franchises granted by the incorporated cities and
towns and by each Louisiana parish that it serves. At September 30, 1994,
the Company held 271 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
See Note 11 of notes to consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
17<PAGE>
EXECUTIVE OFFICERS
The following table sets forth certain information as of September
30, 1994, regarding the executive officers of the Company:
Name Age Office Currently Held
---- --- ---------------------
Charles K. Vaughan 56 Chairman of the Board
Ronald L. Fancher 51 President and Chief Executive
Officer
James F. Purser 44 Executive Vice President and
Chief Financial Officer
Robert F. Stephens 46 Executive Vice President -
Corporate Operations
H.F. Harber 52 Senior Vice President -
Corporate Services
Donald E. James 47 Senior Vice President and
General Counsel
Charles K. Vaughan has served as Chairman of the Board since the
Company's inception on October 18, 1983. From October 1983 through
February 1993, he additionally served as President and Chief Executive
Officer. From March 1993 through May 1994, he served as Chief Executive
Officer. Effective October 1, 1994, Mr. Vaughan elected to take early
retirement from the Company, although he remains Chairman of the Board of
Directors.
Ronald L. Fancher served as a member of the Board of Directors from
February 1984 through February 1993. He has served as President since March
1993 and has held the additional title of Chief Executive Officer since
June 1994. He was also appointed to the Board of Directors in November
1994. Prior to joining the Company, he served as Chairman of the Board and
Chief Executive Officer of Texas Commerce Bank in Odessa, Texas from 1983
until 1993. Additionally, he served as Chairman of the Board and Chief
Executive Officer of Texas Commerce Bank - Lubbock, N.A. in January and
February 1993.
James F. Purser was named Executive Vice President and Chief Financial
Officer in May 1989. He previously served as Senior Vice President and
Chief Financial Officer from August 1988 until May 1989 and as Vice
President from September 1986 until August 1988.
Robert F. Stephens was named Executive Vice President - Corporate
Operations in May 1989. He served as Senior Vice President, Corporate
Operations from January 1988 until May 1989 and as Senior Vice President,
Corporate Services from April 1986 until January 1988. He previously
served as Vice President, Corporate Development and Regulatory Affairs from
August 1984 until April 1986.
H.F. Harber was named Senior Vice President - Corporate Services in
August 1993. He previously served as Vice President, Human Resources and
Administration from July 1991 to August 1993, as Vice President, Human
Resources from May 1990 to July 1991, as Director of Human Resources from
November 1987 until May 1990, as Manager, Compensation and Employment from
18<PAGE>
May 1987 until November 1987, and as Affirmative Action Coordinator from
December 1983 until May 1987.
Donald E. James was named Senior Vice President and General Counsel in
August 1993. He previously served as Senior Vice President - General
Counsel and Corporate Secretary from May 1993 until August 1993, as Senior
Vice President and General Counsel from May 1989 until May 1993, as Vice
President and General Counsel from January 1986 until May 1989, as
Assistant Vice President and General Counsel from August 1985 until January
1986, and as Assistant Vice President and Assistant General Counsel from
February 1984 until August 1985.
19<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER 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, as adjusted for the 3-for-2 stock
split in May 1994, for fiscal 1994 and 1993 are listed below.
<TABLE>
<CAPTION>
1994 1993
---------------------------------- ---------------------------------
Dividends Dividends
High Low paid High Low paid
Quarter ended: --------- --------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
December 31 $21 1/8 $16 3/4 $ .22 $15 7/8 $13 1/2 $ .2125
March 31 20 17 3/4 .22 17 3/4 15 1/8 .2125
June 30 20 1/4 18 .22 19 3/4 16 1/4 .2125
September 30 19 16 3/8 .22 20 5/8 18 5/8 .2125
----- ------
$ .88 $.8500
===== ======
</TABLE>
Prior to its acquisition, GGC made distributions to its shareholders
in fiscal 1994 and 1993 of $120,000 and $893,000, respectively. The
"Dividends paid" information above has not been restated for the pooling of
interests in December 1993, but reflects historical cash dividends paid per
share of Atmos common stock as restated for the 3-for-2 stock split in May
1994.
See Note 3 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, 1994 was 19,881.
20<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data with respect to
the Company and should be read in conjunction with the consolidated
financial statements included herein.
Year ended September 30,
--------------------------------------------
1994 1993 1992 1991 1990
-------- -------- -------- -------- --------
(In thousands, except per share data)
Operating revenues $499,808 $459,641 $403,353 $399,667 $409,975
======== ======== ======== ======== ========
Net income $ 14,679 $ 17,544 $ 10,998 $ 9,612 $ 7,653
======== ======== ======== ======== ========
Net income per
share $ .97 $ 1.22 $ .80 $ .71 $ .60
======== ======== ======== ======== ========
Atmos dividends
declared per
share $ .88 $ .85 $ .83 $ .80 $ .77
======== ======== ======== ======== ========
Total assets at
end of year $416,678 $391,618 $358,363 $338,714 $330,477
======== ======== ======== ======== ========
Long-term debt at
end of year $138,303 $105,853 $112,153 $116,461 $ 88,508
======== ======== ======== ======== ========
Supplemental net
income (1) $ 18,132 $ 10,570 $ 10,130 $ 9,497
======== ======== ======== ========
Supplemental net
income per share $ 1.26 $ .77 $ .75 $ .75
======== ======== ======== ========
(1) Supplemental net income reflects results if GGC had not made
an S Corporation election in 1987.
21<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
The Company distributes and sells natural gas to residential,
commercial, industrial and agricultural customers in six states. Such
business is subject to federal and state regulation and/or regulation by
local authorities in each of the states in which the Company operates. In
addition, the Company's business is affected by seasonal weather patterns,
competitive factors within the energy industry, and economic conditions in
the areas that the Company serves.
A consolidated five-year financial and statistical summary is included
elsewhere herein.
ACQUISITION OF GREELEY GAS COMPANY THROUGH MERGER
The Company has expanded its customer base and sought to diversify the
regulations, weather patterns and local economic conditions to which it is
subject through acquisitions in 1986 and 1987 and 1993. The Company
continues to consider and pursue, where appropriate, additional
acquisitions of natural gas distribution properties and other business
opportunities.
In December 1993, the Company acquired Greeley Gas Company ("GGC") of
Denver, Colorado in a merger transaction accounted for as a pooling of
interests; therefore, all historical financial statements and notes thereto
have been restated to retroactively reflect this merger. At that time,
GGC was a privately held company providing natural gas service to nearly
100,000 customers in 122 communities in Colorado, Kansas and a small
service area in Missouri. The transaction was structured to be a tax-free
reorganization. The Company exchanged 2,329,330 shares of its common stock
before the 3-for-2 stock split (3,493,995 shares on a post-split basis) for
all of the outstanding stock of GGC. For further information regarding the
merger, see Note 2 of notes to consolidated financial statements.
The Company believes that, while the merger may result in some
dilution during the short term, it is expected to be non-dilutive over the
long term with respect to earnings per share. The Company believes this
transaction is consistent with its continuing long-term corporate
development strategy of increasing the value of the Company through
external growth. The Company believes this acquisition will help to
further diversify both the geographic scope of its markets and the mix of
its customer profile, thereby reducing its exposure to changes in the
economic conditions in any given segment of its service area and will add
to diversification in the areas of weather, regulatory environment, and
economic environment. Over the longer term, the Company expects this
combination to contribute to the stability and predictability of earnings
and cash flow.
22<PAGE>
RATE ACTIVITY
In September 1994, the Company filed to increase revenues by
approximately $2.6 million for a portion of its Energas Company service
area ("Energas Division"). The proposed rates would produce an overall
increase of approximately 1.9% of current annual revenues generated from
approximately 217,000 customers and reflects recovery of accrual accounting
of postretirement benefits in accordance with SFAS No. 106. See Note 8 of
the accompanying notes to consolidated financial statements. In November
1994, the Company implemented an annual revenue increase of approximately
$1.5 million affecting about 90% of the customers in this portion of its
Energas Division.
GGC filed a request for an increase in annual revenues of $4.5 million
with the Colorado Public Utility Commission ("Colorado Commission") in
September, 1993. On May 1, 1994, the Company implemented an annual
increase of $3.2 million or 6.9% in Phase I of this proceeding. The Phase
I rates reflect recovery of SFAS No. 106 expenses with external funding,
consistent with the recommended decision of the presiding administrative
law judge. In October 1994, the Colorado Commission issued its order
affirming the increase as set forth in Phase I. The next step in the rate
proceeding will be Phase II, which will address rate redesign issues.
Effective December 1, 1993, GGC received an annual rate increase of
approximately $2.1 million or 10.6% in its Kansas service area. The
increase reflects SFAS No. 106 expenses with external funding and a
moratorium on rate requests in Kansas until December 1, 1996.
On February 11, 1992, the Company filed a rate case with the city of
Amarillo, Texas seeking to increase annual revenues by approximately $4.4
million, or 12%. In November 1992, the Railroad Commission issued its
decision resulting in a total annual increase of $2.1 million. The Company
and the city requested a rehearing of the Order. On January 11, 1993, the
Railroad Commission denied rehearing to both parties. In February 1993,
the city appealed the Railroad Commission's rate order to the District
Court of Travis County, Texas. In January 1994, the District Court denied
the city's appeal. The city has appealed to the Court of Appeals.
During the period of 1991 through 1993, the Company also filed for and
received small rate increases in certain other rate jurisdictions in its
Energas Division totaling approximately $.3 million annually.
The Company filed for a rate increase with the Louisiana Public
Service Commission (the "Louisiana Commission") in November 1991 for its
Louisiana service area ("Trans La Division"). The proposed rates would
produce approximately $3.4 million per year in additional revenues, or an
overall increase of approximately 9.8% for the Trans La Division.
Effective September 3, 1992, the Louisiana Commission granted an increase
of approximately $1.0 million per year in additional revenues, or an
overall increase of approximately 2.8%. The rate order also allowed the
Company to collect franchise taxes as a line item on the Company's bills
which will reduce taxes, other than income taxes, by approximately $800,000
per year. The rate order also approved a rate stabilization clause for
three years that provides for an annual adjustment to the Company's rates
to reflect changes in expenses, revenues and invested capital following an
23<PAGE>
annual review. The rate stabilization clause provides an opportunity for a
return on jurisdictional common equity of between 11.75% and 12.25%. As a
result of the Company's filings under the rate stabilization clause, an
increase of $730,000 annually or 2% went into effect on March 1, 1993, and
an increase of $1.1 million annually or 2.7% went into effect on March 1,
1994.
In September 1990, the Kentucky Public Service Commission (the
"Kentucky Commission") issued an order that increased annual revenues
approximately $1.0 million for the Company's Kentucky service area. In May
1991, the Kentucky Commission issued an Order on Rehearing increasing
allowed revenues an additional $2.6 million. In connection with this rate
case the Company filed a Notice of Appeal with the Kentucky Court of
Appeals in July 1993. The Company's appeal in Kentucky relates solely to
the determination of the appropriate effective date of its last rate
increase in Kentucky. The Kentucky Public Service Commission made the
increase effective in May 1991, while the Company believes it should have
become effective in September 1990. The Company lost the issue at the
trial court level. If the Company is successful, it could recover
approximately $1 million in additional revenue; if it is unsuccessful,
there would be no impact on its revenue. Subsequent to September 30, 1994,
the Kentucky Court of Appeals denied the Company's appeal. The Company is
currently assessing its options for further appeals.
RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED
The Company has not adopted Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment Benefits". See
Note 9 of notes to consolidated financial statements. The rate treatment
of SFAS No. 112 costs has not been determined at this time. Such costs are
currently recorded and recovered in rates on the pay-as-you-go basis. The
Company does not expect the adoption of this standard to have a material
impact on its financial condition or results of operations.
RESULTS OF OPERATIONS
YEAR ENDED SEPTEMBER 30, 1994 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1993
Operating revenues increased to $499.8 million in 1994 from $459.6
million in 1993 due to rate increases received in Kansas, Colorado and
Louisiana, an increase in the number of customers, changes in cost of gas
and increased volumes sold. Average gas sales revenues per thousand cubic
feet ("Mcf") increased from 1993 by $.12 to $4.14 in 1994, while the
average cost of gas per Mcf sold increased $.15 to $2.86 in 1994. The
number of meters in service increased to 649,319 at September 30, 1994
compared with 636,159 at September 30, 1993. Although the weather was 2%
warmer in 1994 than in 1993, it was only slightly warmer than normal.
Sales to residential, commercial and public authority customers decreased
approximately .5 billion cubic feet ("Bcf") in 1994, but sales to
industrial and agricultural customers increased approximately 7 Bcf. Total
sales volumes increased 6.7 Bcf to 116.1 Bcf in 1994, as compared with
1993. Revenues from gas transported for others decreased $.9 million to
approximately $14.1 million in fiscal 1994 due to a decrease in volumes
transported of 4.5 Bcf to 35.3 Bcf in 1994.
24<PAGE>
Gross profit increased by approximately 3% to $168.2 million in 1994
from $163.1 million in 1993. The primary factors contributing to the
higher gross profit were increased prices and volumes, as discussed above.
Operating expenses, excluding income taxes, increased to $133.7 million in
1994 from $122.8 million in 1993 due to increased operation expense and
depreciation. Operation expense increased $9.9 million due to increased
distribution expense, employee welfare expenses including adoption of SFAS
No. 106, GGC acquisition and assimilation costs, and the cost of an early
retirement program in the Greeley Gas Division in the fourth quarter. SFAS
No. 106 expenses in excess of pay-as-you-go expenses were approximately
$3.8 million in 1994. The Company has been successful in seeking recovery
of SFAS No. 106 expenses in a portion of its service areas and will
continue to seek recovery in its remaining service areas (Note 8). GGC
acquisition and assimilation costs were approximately $1.5 million in 1994
compared with approximately $.5 million in 1993. The cost of the early
retirement program was approximately $1.3 million in 1994. The acquisition
and assimilation costs as well as the early retirement program are one-time
costs associated with the GGC acquisition. Income taxes decreased to $8.1
million for 1994 from $10.1 million for 1993. The primary reasons for the
decrease were lower pre-tax profits and a lower effective tax rate. The
effective tax rate decreased to 35.6% in 1994 from 36.5% in 1993. This was
primarily due to the impact of permanent differences on the lower pre-tax
profits in 1994. Operating income decreased in 1994 by approximately 13%
to $26.5 million from $30.3 million in 1993. The decrease in operating
income resulted primarily from increased operating expenses as discussed
above.
Net income decreased in 1994 by approximately 16% to $14.7 million
from $17.5 million in the prior year. This decrease in net income resulted
primarily from a decrease in operating income, which was partially offset
by a $1.0 million decrease in interest expense. Net income per share
decreased to $.97 for 1994 from $1.22 for 1993, reflecting the effects of
an increase in average shares outstanding of approximately 6%. One-time
acquisition costs, assimilation expenses and an early retirement program in
Greeley Gas Company, as well as the effect of adopting SFAS No. 106,
reduced earnings per share by approximately $.22 in 1994.
YEAR ENDED SEPTEMBER 30, 1993 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1992
Operating revenues increased to $459.6 million in 1993 from $403.4
million in 1992 due to colder weather, increased sales volumes and revenues
for every customer type, rate increases received in Texas and Louisiana,
and an increased number of customers in fiscal 1993. Total sales volumes
increased 9.7 Bcf to 109.4 Bcf in 1993, as compared with 1992. Average gas
sales revenues per Mcf increased $.16 to $4.02 in fiscal 1993 from 1992,
while the average cost of gas per Mcf sold increased $.13 to $2.71. The
number of meters in service increased to 636,159 at September 30, 1993
compared with 630,365 at September 30, 1992. Weather was 10% colder in
1993 than 1992, and was 2% colder than normal. Because of this colder
weather, sales volumes to weather sensitive residential, commercial and
public authority customers increased 5.8 Bcf, or 8%, to 78.0 Bcf in 1993,
as compared with 1992. Sales volumes to industrial and agricultural
customers increased 3.9 Bcf, or 14%, because of increased irrigation fuel
demand in the Company's West Texas service area. Revenues from gas
25<PAGE>
transported for others increased $1.3 million to approximately $15.0
million in 1993. Average transportation fees decreased from $.42 per Mcf
to $.38 per Mcf, while transportation volumes increased 7.6 Bcf to 39.8 Bcf
in 1993 as compared with 1992. Average transportation fees decreased in
1993 because of increased competition for large volume customers in
Kentucky.
Gross profit increased by approximately 12% to $163.1 million in 1993
from $146.3 million in 1992. The primary factors contributing to the
higher gross profit were increased rates and colder weather, as discussed
above. Operating expenses, excluding income taxes, increased to $122.8
million in 1993 from $117.9 million in 1992 due to increased operating
activity. Operation expense increased $3.5 million due to increased
distribution expenses, outside services, wages and benefits expense.
Income taxes increased to $10.1 million for 1993 from $4.8 million for
1992. The primary reasons for the increase were higher pre-tax profits and
a higher effective tax rate. The effective tax rate increased to 36.5% in
1993 from 30.2% in 1992 because of reduced significance of permanent
differences due to higher pre-tax profits and a one percent increase in the
statutory rate to 35%, effective January 1, 1993. Operating income
increased in 1993 by approximately 28% to $30.3 million. The increase in
operating income resulted primarily from increased gross profit.
Net income increased in 1993 by approximately 60% to $17.5 million
from $11.0 million in 1992. This increase in net income resulted primarily
from the increase in operating income. Also, interest expense decreased
$.5 million in 1993, as compared with 1992, due to lower weighted average
interest rates. Net income per share increased approximately 53% to $1.22
for 1993 compared with 1992, including the effects of an increase in
average shares outstanding of approximately 4%.
CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of Cash
Flows")
Cash Flows from Operating Activities
Cash flows from operating activities totaled $41.2 million for 1994
compared with $37.1 million for 1993 and $31.4 million for 1992. The
decrease in net income in 1994 as compared with 1993 was more than offset
by the net changes in assets and liabilities. Gas stored underground
decreased in 1994 because of substantially lower gas prices during the
summer of 1994 when the storage reservoir was being refilled. The $10.9
million increase in deferred charges and other assets in 1993 related to
the $8.4 million increase in deferred credits and other liabilities and
recognized funding for the Supplemental Executive Benefits Plan. See
"Consolidated Statements of Cash Flows" for other changes in assets and
liabilities.
Cash Flows from Investing Activities
Net cash used in investing activities totaled $48.4 million in 1994
compared with $42.2 million in 1993 and $39.5 million in 1992. Capital
expenditures in fiscal 1994 amounted to $50.4 million compared with $43.1
million in 1993 and $42.2 million in 1992. Currently budgeted capital
expenditures for 1995 total $56.1 million and include major expenditures
26<PAGE>
for mains, services, meters, vehicles and computer software. Such
expenditures will be financed from internally generated funds and financing
activities, as discussed below.
Cash Flows from Financing Activities
Net cash provided by financing activities totaled $7.7 million for
1994 compared with $3.7 million for 1993 and $8.3 million in 1992.
Financing activities during these periods included issuance of common
stock, dividend payments, borrowings from banks, and issuance and
repayments of long-term debt.
Cash dividends and distributions paid. The Company paid $12.7 million
in cash dividends and distributions during 1994. The $2.6 million increase
over 1993 primarily reflects an increase in the Company's quarterly
dividend rate and an increase in the number of shares of common stock
outstanding in 1994. The Company has increased its historical dividend
rate in each of the last six years.
Short-term financing activities. At September 30, 1994, the Company
had committed lines of credit totaling $72.0 million, all of which was
unused, in order to provide for short-term cash requirements. These credit
facilities are negotiated at least annually. At September 30, 1994, the
Company also had uncommitted short-term credit lines of $130.0 million, of
which $71.9 million was unused. At September 30, 1994, $40.0 million of
notes payable to banks were classified noncurrent and long-term financing
was completed subsequent to September 30, 1994. During 1994, notes payable
increased $22.4 million compared with increases of $2.6 million during 1993
and $18.6 million in 1992. The increases in 1994 and 1992 were primarily
due to funding of capital expenditures and repayment of long-term debt.
The increase in 1993 was less than the increases in 1994 and 1992, partly
because of funds provided in 1993 from stock issued under the Direct Stock
Purchase Plan.
Long-term financing activities. Payments of long-term debt increased
$5.4 million to $9.9 million for the year ended September 30, 1994 compared
with the year ended September 30, 1993. Payments of long-term debt
consisted of a $3.0 million installment on the Company's 9.75% Senior Notes
due in 1996, a $2.0 million installment on the 11.2% Senior Notes, the
balance of $3.25 million on the 13.75% Series I First Mortgage Bonds and
the balance of $1.6 million on the 13% Series G First Mortgage Bonds. At
September 30, 1994, the Company was negotiating the private placement of
$40.0 million of Senior Notes with two insurance companies. Scheduled
payments of long-term debt in fiscal 1993 consisted of a $3.5 million
installment on the Company's 9.75% Senior Notes and a $1.0 million payment
on the 13.75% Series I First Mortgage Bonds. No long-term debt was issued
in 1993. The Company entered into an agreement with an insurance company
in August 1992, for a private placement of $10.0 million of unsecured
Senior Notes due in annual installments of $1.0 million from 1997 through
2006, with interest to be paid semiannually at 7.95%. The net proceeds
from the sale of the Senior Notes were used primarily to refinance an 8.4%
note in the amount of $9.8 million. The Company also made scheduled
installments of $4.5 million on its 9.75% Senior Notes, $1.0 million on the
13.75% Series I First Mortgage Bonds and a $.3 million installment on GGC's
13% Series G First Mortgage Bonds in fiscal 1992. The loan agreements
27<PAGE>
pursuant to which all the Company's Senior Notes have been issued contain
covenants by the Company with respect to the maintenance of certain debt-
to-equity ratios and cash flows, and restrictions on the payment of
dividends. Also see Note 3 of notes to consolidated financial statements.
Issuance of common stock. The Company issued 428,264, 897,089 and
306,880 shares of common stock in 1994, 1993 and 1992, respectively, for
its Direct Stock Purchase Plan ("DSPP"), Employee Stock Ownership Plan and
Incentive Stock Option Plan. The DSPP was implemented in August 1992.
The DSPP has been amended to remove the direct stock purchase feature of
the plan and has been renamed the Atmos Energy Corporation Dividend
Reinvestment and Stock Purchase Plan ("DRSPP"). In 1994, 1993 and 1992,
173,801, 760,089 and 132,249 shares, respectively, were issued under the
plan, generating proceeds of $3.0 million, $13.4 million and $1.9 million,
respectively. At September 30, 1994, 712,596 shares were available for
future issuance under the plan.
The Company believes that internally generated funds, its short-term
credit facilities and access to the debt and equity capital markets will
provide necessary working capital and liquidity for capital expenditures
and other cash needs for 1995.
Seasonality
The Company's natural gas distribution business is seasonal due to
weather conditions in the Company's service areas. Gas sales are affected
by winter heating season requirements, and sales to agricultural customers
(who use natural gas as fuel in the operation of irrigation pumps) during
the period from April through September may be affected by rainfall
amounts. These factors generally result in higher operating revenues and
net income during the period from October through March of each year and
lower operating revenues and either net losses or lower net income during
the period from April through September of each year.
The following table sets forth, on an unaudited basis, the Company's
quarterly operating revenues, quarterly operating revenues as a percentage
of annual operating revenues, quarterly net income (loss) and quarterly net
income (loss) as a percentage of annual net income for its past two fiscal
years.
28 <PAGE>
<TABLE>
<CAPTION>
Quarter ended
---------------------------------------------------
Year ended September 30, December 31 March 31 June 30 September 30 Total
------------------------ ------------ --------- -------- ------------ ----------
(In thousands, except for percentages)
<S> <C> <C> <C> <C> <C>
1994
----
Operating revenues $145,501 $186,944 $90,013 $77,350 $499,808
29% 37% 18% 16% 100%
Net income (loss) $ 7,088 $ 13,242 $(1,224) $(4,427) $ 14,679
48% 90% (8)% (30)% 100%
1993
----
Operating revenues $130,700 $166,238 $91,219 $71,484 $459,641
28% 36% 20% 16% 100%
Net income (loss) $ 6,765 $ 13,760 $ 831 $(3,812) $ 17,544
39% 78% 5% (22)% 100%
</TABLE>
Inflation
The Company believes that inflation has caused and will
continue to cause increases in certain operating expenses and has
required assets and will continue to require assets to be re-
placed at higher costs. The Company continually reviews 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.
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 oper-
ated in substantial conformity with all applicable environmental
statutes and regulations. There are no administrative or judi-
cial 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.
29<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page no.
Report of independent auditors 30
Consolidated balance sheets 31
Consolidated statements of income 32
Consolidated statements of shareholders' equity 33
Consolidated statements of cash flows 34
Notes to consolidated financial statements 36
Supplementary data (unaudited) 57
30<PAGE>
REPORT OF ERNST & YOUNG LLP,
INDEPENDENT AUDITORS
Board of Directors
Atmos Energy Corporation
We have audited the accompanying consolidated balance sheets
of Atmos Energy Corporation at September 30, 1994 and 1993, and
the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period
ended September 30, 1994. Our audits also included the financial
statement schedules listed in the Index at Item 14(a). These
financial statements and schedules are the responsibility of the
Company's management. Our responsibility is to express an
opinion on these financial statements and schedules based on our
audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
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,
1994 and 1993, and its consolidated results of operations and its
cash flows for each of the three years in the period ended
September 30, 1994 in conformity with generally accepted
accounting principles. Also, in our opinion, the related
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
Ernst & Young LLP
Dallas, Texas
November 9, 1994
31<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS September 30,
1994 1993
-------- --------
ASSETS (In thousands, except share data)
Property, plant and equipment
Utility plant $537,834 $496,153
Construction in progress 5,858 5,359
-------- --------
543,692 501,512
Less accumulated depreciation and
amortization 216,285 202,237
-------- --------
Net property, plant and equipment 327,407 299,275
Current assets
Cash and cash equivalents 2,766 2,286
Accounts receivable, less allowance for
doubtful accounts of $787 in 1994
and $963 in 1993 29,678 29,200
Inventories 5,888 6,064
Gas stored underground 12,657 17,603
Prepayments 2,309 4,240
-------- --------
Total current assets 53,298 59,393
Deferred charges and other assets 35,973 32,950
-------- --------
$416,678 $391,618
CAPITALIZATION AND LIABILITIES ======== ========
Shareholders' equity
Common stock, no par value (stated at $.005
per share); authorized 50,000,000 shares;
issued and outstanding 1994 - 15,297,166
shares, 1993 - 14,868,902 shares $ 77 $ 74
Additional paid-in capital 102,456 94,279
Retained earnings 47,023 45,076
-------- --------
Total shareholders' equity 149,556 139,429
Long-term debt 138,303 105,853
-------- --------
Total capitalization 287,859 245,282
Current liabilities
Current maturities of long-term debt 4,000 6,300
Notes payable to banks 18,100 35,700
Accounts payable 21,975 27,803
Taxes payable 4,864 3,797
Customers' deposits 8,257 7,862
Other current liabilities 7,038 6,455
-------- --------
Total current liabilities 64,234 87,917
Deferred income taxes 30,184 32,614
Deferred credits and other liabilities 34,401 25,805
-------- --------
$416,678 $391,618
======== ========
See accompanying notes to consolidated financial statements.
32<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended September 30,
-------------------------------
1994 1993 1992
-------- -------- --------
(In thousands, except per share data)
Operating revenues $499,808 $459,641 $403,353
Purchased gas cost 331,571 296,532 257,091
-------- -------- --------
Gross profit 168,237 163,109 146,262
Operating expenses
Operation 92,132 82,185 78,642
Maintenance 5,888 6,335 5,695
Depreciation and amortization 18,841 17,433 17,205
Taxes, other than income 16,808 16,806 16,398
Income taxes 8,102 10,073 4,753
-------- -------- --------
Total operating expenses 141,771 132,832 122,693
-------- -------- --------
Operating income 26,466 30,277 23,569
Other income (expense)
Interest income 168 327 376
Other, net 335 239 876
-------- -------- --------
Total other income 503 566 1,252
Interest charges 12,290 13,299 13,823
-------- -------- --------
Net income $ 14,679 $ 17,544 $ 10,998
======== ======== ========
Net income per share $ .97 $ 1.22 $ .80
======== ======== ========
Atmos dividends declared
per share (Note 2) $ .88 $ .85 $ .83
======== ======== ========
Average shares outstanding 15,195 14,338 13,789
======== ======== ========
See accompanying notes to consolidated financial statements.
33<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF
SHAREHOLDERS' EQUITY Common stock
---------------- Additional
Number of Stated paid-in Retained
shares value capital earnings
---------- ------ ------- --------
(In thousands, except share data)
Balance at September 30,
1991, as adjusted for
the 3-for-2 stock split 10,170,938 $ 51 $73,392 $16,867
Adjustment for pooling of
interests with GGC (Note 2) 3,493,995 17 941 19,690
---------- ---- ------- -------
Balance, September 30, 1991,
as restated 13,664,933 68 74,333 36,557
Net income - - - 10,998
Cash dividends ($.83 per share) - - - (8,516)
GGC distributions - - - (402)
Common stock issued
Stock option plan 6,750 - 71 -
Direct stock purchase plan 132,249 1 1,849 -
Employee stock ownership
plan 167,881 1 2,288 -
---------- ---- ------- -------
Balance, September 30, 1992 13,971,813 70 78,541 38,637
Net income - - - 17,544
Cash dividends ($.85 per share) - - - (9,262)
GGC distributions - - - (893)
Common stock issued
Stock option plan 6,000 - 60 -
Direct stock purchase plan 760,089 3 13,401 -
Employee stock ownership
plan 131,000 1 2,277 -
Less: GGC net income for
the quarter ended
December 31, 1992 (Note 2) - - - (950)
---------- ---- ------- -------
Balance, September 30, 1993 14,868,902 74 94,279 45,076
Net income - - - 14,679
Cash dividends ($.88 per share) - - - (12,612)
GGC distributions - - - (120)
Common stock issued
Restricted stock grant plan 105,000 1 2,134 -
Direct stock purchase plan 173,801 1 3,037 -
Employee stock ownership
plan 149,463 1 2,713 -
Other - - 293 -
---------- ---- ------- -------
Balance, September 30, 1994 15,297,166 $ 77 $102,456 $47,023
========== ==== ======= =======
See accompanying notes to consolidated financial statements.
34<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended September 30,
1994 1993 1992
-------- ------- -------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $14,679 $16,594 $10,998
Adjustments to reconcile net income
to net cash provided by operating
activities
Depreciation and amortization
Charged to depreciation and
amortization 18,841 16,480 17,205
Charged to other accounts 1,476 3,377 4,598
Deferred income taxes 244 2,733 349
Other 2,101 622 281
------- ------- -------
37,341 39,806 33,431
Change in assets and liabilities
(Increase) decrease in accounts
receivable (478) 1,564 (2,202)
(Increase) decrease in inventories 176 708 (84)
(Increase) decrease in gas stored
underground 4,946 (6,176) (14)
(Increase) decrease in prepayments 1,931 1,873 (287)
(Increase) decrease in deferred
charges and other assets (3,824) (10,908) 586
Increase (decrease) in accounts
payable (7,128) (58) 1,196
Increase (decrease) in taxes
payable (1,314) 195 930
Increase (decrease) in customers'
deposits 395 (61) 322
Increase in other current
liabilities 583 1,804 803
Increase (decrease) in deferred
credits and other liabilities 8,596 8,398 (3,269)
------- ------- -------
Net cash provided by operating
activities 41,224 37,145 31,412
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (50,355) (43,143) (42,169)
Retirements of property, plant and
equipment 1,906 935 2,629
------- ------- -------
Net cash used in investing
activities (48,449) (42,208) (39,540)
- Continued -
35<PAGE>
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Year ended September 30,
1994 1993 1992
-------- -------- --------
(In thousands)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase in notes payable $ 22,400 $ 2,563 $18,636
Proceeds from issuance of
long-term debt - - 10,000
Cash dividends and distributions
paid (12,732) (10,155) (8,918)
Repayment of long-term debt (9,850) (4,500) (15,608)
Issuance of common stock 7,887 15,742 4,210
-------- ------- -------
Net cash provided by financing
activities 7,705 3,650 8,320
-------- ------- -------
Net increase (decrease) in cash and
cash equivalents 480 (1,413) 192
Cash and cash equivalents at
beginning of year 2,286 3,699 3,507
-------- ------- -------
Cash and cash equivalents at end
of year $ 2,766 $ 2,286 $ 3,699
======== ======= =======
See accompanying notes to consolidated financial statements.
36 <PAGE>
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of significant accounting policies
Description of business - Atmos Energy Corporation and its
subsidiaries ("Atmos" or the "Company") are in the business of
distributing natural gas to residential, commercial, industrial
and agricultural customers within service areas located in Texas,
Louisiana, Kentucky, Colorado, Kansas and a small portion of
Missouri. Such business is subject to federal and state
regulation and/or regulation by local authorities in each of the
six states in which the Company operates. The Company has no
other material business segments.
Principles of consolidation - The accompanying consolidated
financial statements include the accounts of Atmos Energy Corpora-
tion and its subsidiaries. Each subsidiary is wholly-owned and
all material intercompany items have been eliminated.
Revenue recognition - Sales of natural gas are billed on a
monthly cycle basis; however, the billing cycle periods for
certain classes of customers do not necessarily coincide with ac-
counting 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 ex-
pense. Estimated losses due to credit risk are reserved at the
time revenue is recognized.
Property, plant and equipment - Property, plant and equipment
is stated at original cost net of contributions in aid of constru-
ction. The cost of additions includes an allowance for funds used
during construction and applicable overhead charges. Major
renewals and betterments are capitalized, while the costs of
maintenance and repairs are charged to expense as incurred.
Property, plant and equipment is depreciated at various rates on a
straight-line basis over the estimated useful lives of the assets.
In the first quarter of fiscal 1993, the Company changed the
estimated average useful lives used to compute depreciation for
certain utility plant assets. These changes resulted from revised
estimates of the projected economic life of the affected assets
based on recent orders received from regulatory bodies having
jurisdiction over the Company and independently performed
depreciation service life studies. The effect of this change on
net income for the year ended September 30, 1993 was an increase
of $1,104,000. The composite rates were 3.5% and 3.7% for the
years ended September 30, 1994 and 1993, respectively. At the
time property, plant and equipment is retired, the cost, plus
removal expenses and less salvage, is charged to accumulated
depreciation.
37<PAGE>
Inventories - Inventories consist of materials and supplies
and merchandise held for resale. Inventories are stated at the
lower of average cost or market.
Gas stored underground - Net additions of inventory gas to
underground storage and withdrawals of inventory gas from storage
are priced using the average cost method. Non-current gas in
storage is classified as property, plant and equipment and is
priced at cost.
Income taxes - The Company provides deferred income taxes for
significant temporary differences in the recognition of revenues
and expenses for tax and financial reporting purposes.
Cash and cash equivalents - The Company considers all highly
liquid debt instruments purchased with a maturity of three months
or less to be cash equivalents.
Deferred charges and other assets - Deferred charges and
other assets at September 30, 1994 and 1993 include assets of the
Company's qualified defined benefit retirement plans in excess of
the plans' obligations in the amounts of $12,275,000 and
$13,289,000, respectively, and Company assets related to the
nonqualified retirement plans at September 30, 1994 and 1993 of
$15,735,000 and $12,758,000, respectively. At September 30, 1994,
a payable of $1,300,000 was recorded for expenses related to an
early retirement program under Greeley Gas Company's qualified
defined benefit retirement plan.
Deferred credits and other liabilities - Deferred credits and
other liabilities include customer advances for construction of
$8,428,000 and $7,769,000 at September 30, 1994 and 1993, respect-
ively; obligations under capital leases of $6,294,000 and
$6,389,000 at September 30, 1994 and 1993, respectively; and
obligations under the Company's nonqualified retirement plans of
$11,151,000 and $8,317,000 at September 30, 1994 and 1993,
respectively.
Earnings per share - The calculation of primary earnings per
share is based on reported net income divided by weighted average
common shares outstanding. The Company does not have other class-
es of stock or dilutive common stock equivalents. See Note 2 for
a discussion of supplemental net income per share.
2. Greeley Gas Company acquisition
On December 22, 1993, Atmos acquired by means of a merger all
of the assets and liabilities of Greeley Gas Company ("GGC") in
accordance with the terms and provisions of an Agreement and Plan
of Reorganization dated July 2, 1993. GGC is a natural gas
utility engaged in the distribution and sale of natural gas to
residential, commercial, industrial, agricultural, and other
customers throughout Colorado, Kansas, and a small portion of
Missouri. All of the shares of GGC's common stock were exchanged
for a total of 3,493,995 shares of Atmos common stock as adjusted
38<PAGE>
for a 3-for-2 stock split (2,329,330 shares on a pre-split basis).
See Note 5 for information regarding the stock split in May 1994.
This merger transaction was accounted for as a pooling of interes-
ts; therefore, all historical financial statements and notes
thereto have been restated. Subsequent to the merger, the
business of GGC has been operated through the Company's Greeley
Gas Company division (the "Greeley Gas Division").
GGC prepared its financial statements on a December 31 fiscal
year end. GGC's fiscal year has been changed to September 30 to
conform to the Company's year end. The restated September 30,
1993 balance sheet, as presented, is the combined balance sheets
of Atmos and GGC as of September 30, 1993. The restated
consolidated statements of income and cash flows for the year
ended September 30, 1992 include Atmos operations for the year
then ended and GGC operations for the year ended December 31,
1992. The restated consolidated statement of income for the year
ended September 30, 1993 includes Atmos and GGC operations for the
twelve months then ended. As a result, GGC's operations for the
three months ended December 31, 1992 (operating revenue of
$18,322,842 and net income of $950,185) are included in both the
1993 and 1992 restated statements of income, the GGC net income
for this period has been deducted in calculating the shareholders'
equity balances at September 30, 1993 and cash flows for the year
then ended.
In 1987, GGC elected classification as an S Corporation
(small business corporation) under the provisions of the Internal
Revenue Code. Normally, income taxes are not reported in the
financial statements of S Corporations as the liability for
payment of federal and state income taxes is the direct responsib-
ility of the shareholders. However, during 1991, as part of the
settlement of rate cases filed in the states of Colorado and
Kansas, GGC was ordered to begin providing for current and de-
ferred income taxes. Accordingly, the Company's restated 1991
financial statements include a one-time charge to income of
$1,081,202 to reinstate deferred income taxes for GGC. Supple-
mental net income and earnings per share of the Company are
presented below to eliminate the one-time charge and to reflect
income tax expense in periods prior to 1994 as if GGC had not made
the S Corporation election in 1987.
Year ended September 30,
1993 1992
-------- --------
(In thousands, except per share data)
Supplemental net income $ 18,132 $ 10,570
======== ========
Supplemental net income
per share $ 1.26 $ .77
======== ========
39<PAGE>
Results of operations and net income for the previously
separate companies for periods prior to the merger are as follows:
Quarter ended Year ended September 30,
December 31, 1993 1993 1992
----------------- -------- --------
(In thousands)
Operating revenues
Atmos $119,223 $388,495 $340,117
GGC 26,278 71,146 63,236
-------- -------- --------
$145,501 $459,641 $403,353
======== ======== ========
Net income
Atmos $ 5,458 $ 15,712 $ 10,031
GGC 1,630 1,832 967
-------- -------- --------
$ 7,088 $ 17,544 $ 10,998
======== ======== ========
The dividends per share presentation on the consolidated
statements of income reflects Atmos dividends declared per share
as adjusted for the 3-for-2 stock split in May 1994. The
dividends declared by Atmos reflect the per share dividends
declared by Atmos Energy Corporation for each of the three years
ended September 30, 1994. The restated cash dividends and
distributions per share reflect the total amounts paid by Atmos
and GGC to their shareholders in each of those three years,
divided by the total amount of weighted average shares outstanding
in those periods as restated for the shares issued to effect the
merger between Atmos and GGC and the 3-for-2 stock split in May
1994.
Year ended September 30,
------------------------
1994 1993 1992
---- ---- ----
Atmos dividends declared
per share $.88 $.85 $.83
==== ==== ====
Restated cash dividends and
distributions per share,
including GGC $.84 $.71 $.65
==== ==== ====
40<PAGE>
3. Long-term debt and notes payable
Long-term debt at September 30, 1994 and 1993 consisted of
the following:
1994 1993
--------- --------
(In thousands)
Unsecured 7.95% Senior Notes, payable
in annual installments of $1,000,000
beginning August 31, 1997 through
August 31, 2006 with semiannual
interest payments $ 10,000 $ 10,000
Unsecured 9.57% Senior Notes, payable
in annual installments of $2,000,000
beginning September 30, 1997 through
September 30, 2006 with semiannual
interest payments 20,000 20,000
Unsecured 9.76% Senior Notes, payable
in annual installments of $3,000,000
beginning December 30, 1995 through
December 30, 2004 with semiannual
interest payments 30,000 30,000
Unsecured 9.75% Senior Notes, payable
in varying annual installments
through December 30, 1996 5,000 8,000
Unsecured 11.2% Senior Notes, payable in
annual installments of $2,000,000
beginning December 30, 1993 through
December 30, 2002 with semiannual
interest payments 18,000 20,000
First Mortgage Bonds, 9.4% Series J, due
May 1, 2021 17,000 17,000
First Mortgage Bonds, 13% Series G - 1,600
Unsecured 10% Notes, due December 31,
2011 2,303 2,303
First Mortgage Bonds, 13.75% Series I - 3,250
Notes payable to banks financed with
long-term debt 40,000 -
-------- --------
142,303 112,153
Less amounts classified as current (4,000) (6,300)
-------- --------
$138,303 $105,853
======== ========
Subsequent to September 30, 1994, the Company obtained
commitments to enter into new note purchase agreements with two
insurance companies to issue at par $20,000,000 of unsecured
Senior Notes at 8.07% payable in annual installments of $4,000,000
beginning October 31, 2002 through October 31, 2006 with semi-
annual interest payments and $20,000,000 of unsecured Senior Notes
at 8.26% payable in annual installments of $1,818,182 beginning
October 31, 2004 through October 31, 2014 with semiannual interest
payments. At September 30, 1994, $40,000,000 of notes payable to
banks were classified as long-term.
41<PAGE>
The Company entered into a note purchase agreement with an
insurance company in August 1992, for a private placement of
$10,000,000 of unsecured Senior Notes at 7.95%. The net proceeds
from the sale of the Senior Notes were used primarily to refinance
an 8.4% note in the amount of $9.8 million.
The Company may prepay any of the Senior Notes in whole at any
time, subject to a prepayment premium. The note agreements
provide for certain cash flow requirements and restrictions on
additional indebtedness, sale of assets and payment of dividends.
Under the most restrictive of such covenants, cumulative cash
dividends paid after September 30, 1988 may not exceed the sum of
75% of accumulated net income for periods after September 30, 1988
plus $12,000,000 plus the proceeds from the sale of common stock
after September 30, 1988. At September 30, 1994, approximately
$44,492,000 of shareholders' equity was not so restricted.
As of September 30, 1994, all of the Company's utility plant
assets in Colorado, Kansas and Missouri with a book value of
approximately $59,173,000 are subject to a lien under the 9.4%
Series J First Mortgage Bonds assumed by the Company in the
acquisition of GGC.
Maturities of long-term debt are as follows (in thousands):
1995 $ 4,000
1996 7,000
1997 9,000
1998 8,000
1999 8,000
Thereafter 106,303
--------
$142,303
========
Notes payable to banks
The Company has committed short-term, unsecured bank credit
facilities totaling $72,000,000, all of which was unused at
September 30, 1994. One facility of $60,000,000 requires a
commitment fee of 1/8 of 1% on the unused portion. A second
facility for $12,000,000 requires a commitment fee of 3/16 of 1%
on the unused portion. The committed lines are renewed or
renegotiated at least annually.
The Company also had aggregate uncommitted credit lines of
$130,000,000, of which $71,900,000 was unused as of September 30,
1994. 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.
42<PAGE>
Information related to notes payable to banks follows:
1994 1993 1992
-------- -------- --------
(In thousands, except for percents)
Notes outstanding at September 30
prior to long-term financing $58,100 $35,700 $32,600
Reclassification for long-term
financing subsequent to year end (40,000) - -
-------- -------- --------
Notes outstanding at September 30 $18,100 $35,700 $32,600
Weighted average interest rate at
September 30 5.6% 4.1% 4.7%
Maximum amount outstanding during
the year $58,100 $50,300 $36,800
Daily average amount outstanding
during the year $26,597 $19,801 $12,078
Weighted average interest rate
during the year computed on a
daily basis 4.3% 4.2% 5.3%
Notes payable to shareholders and employees
Notes payable to shareholders and employees of GGC were
outstanding at times prior to September 30, 1993. They were for
six-month terms and bore interest at rates ranging from 4.0% to
4.5%. Interest incurred on such notes aggregated $11,326 and
$28,593 for 1993 and 1992, respectively.
4. Income taxes
The components of income tax expense for 1994, 1993 and 1992
are as follows:
1994 1993 1992
------- ------- -------
(In thousands)
Current $7,858 $7,340 $4,653
Deferred 244 2,733 100
------ ------ ------
$8,102 $10,073 $4,753
====== ====== ======
Included in the provision for income taxes are state income
taxes of $328,000, $890,000, and $403,000 for 1994, 1993, and
1992, respectively.
Effective October 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS No. 109") and, as permitted under the new rules,
prior years' financial statements have not been restated.
Adoption of the new standard in 1994 had no significant effect on
net income.
This standard changes the Company's method of accounting for
income taxes from the deferred method (APB 11) to the liability
43<PAGE>
method. Previously the Company deferred the past tax effects of
timing differences between financial reporting and taxable income.
Under the liability method of SFAS No. 109, deferred tax assets
and liabilities are recognized for the estimated future tax
effects of differences between the financial statement carrying
amounts of existing assets and liabilities and their respective
tax bases.
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, 1994 and October 1, 1993 are
presented below (in thousands):
1994 1993
------- -------
Deferred tax assets
Costs expensed for book purposes
and capitalized for tax purposes $ 914 $ 744
Accruals not currently deductible
for tax purposes 1,929 689
Customer advances 2,365 2,128
Nonqualified benefit plans 5,074 2,740
Postretirement benefits 1,442 -
Other, net 1,198 1,407
------- -------
Total deferred tax assets 12,922 7,708
Deferred tax liabilities
Tax and book basis of utility plant 37,316 31,949
Prepaid pensions 4,640 5,134
Other, net 1,150 565
------- -------
Total deferred tax liabilities 43,106 37,648
------- -------
Net deferred tax liabilities $30,184 $29,940
======= =======
SFAS No. 109 deferred accounts for
rate regulated entities (included
in other deferred credits):
Liabilities $ 2,647 $ 2,673
======= =======
44<PAGE>
During 1993 and 1992, deferred income taxes were provided for
significant timing differences in recognition of revenues and
expenses for tax and financial reporting purposes. The effects of
these timing differences at September 30, 1993 and 1992 were as
follows:
1993 1992
------ ------
(In thousands)
Excess of tax over financial
depreciation and amortization $1,754 $ 351
Items capitalized for financial
reporting and recognized currently
for tax reporting 416 388
Deferred gas service revenue
recognized currently for tax
reporting 1,464 453
Other, net (901) (1,092)
------ ------
Total deferred income taxes $2,733 $ 100
====== ======
Reconciliations of the provisions for income taxes computed
at the statutory rate to the reported provisions for income taxes
for 1994, 1993 and 1992 are set forth below:
Liability
Method Deferred Method
--------- -----------------
1994 1993 1992
-------- ------- ------
(In thousands)
Tax at statutory rate of 34%
through December 31, 1992
and 35% thereafter $ 7,992 $ 9,603 $5,356
Financial expenses, not deductible
for tax reporting 503 680 218
Common stock dividends deductible
for tax reporting (573) (462) (446)
State taxes 328 682 244
Other, net (148) (430) (619)
------- ------- ------
Provision for income taxes $ 8,102 $10,073 $4,753
======= ======= ======
5. Stock split
On February 9, 1994, the Board of Directors of Atmos approved
a 3-for-2 split of its common stock implemented in the form of a
stock dividend, which resulted in shareholders receiving one new
share for every two shares held. Fractional shares were not
issued but were paid in cash or credited to the accounts of
participants of the Dividend Reinvestment and Stock Purchase Plan
("DRSPP") and ESOP. The record date for the split was May 4, 1994
and the payment date for mailing the new shares and cash for
fractional shares to shareholders was May 16, 1994. All share and
45<PAGE>
per share amounts in the financial statements and notes thereto
have been restated to reflect this split, unless otherwise noted.
6. Common stock and stock options
The Company issued 428,264 shares of its common stock in
fiscal 1994 in connection with its Direct Stock Purchase Plan,
Restricted Stock Grant Plan and Employee Stock Ownership Plan. It
also issued common stock in connection with the GGC merger (Note
2) and the stock split (Note 5).
The Company has an Employee Stock Ownership Plan as discussed
in Note 7. The Company has registered 600,000 shares for issuance
under the plan, of which 134,776 shares were available for future
issuance on September 30, 1994.
In August 1992 the Company announced a Direct Stock Purchase
Plan ("DSPP") which was the successor to and replacement for the
Dividend Reinvestment Plan ("DRP"). Members of the DRP were
automatically enrolled in the DSPP. In November 1993, the Company
amended the DSPP to remove the direct stock purchase feature of
the plan and to rename the plan the Atmos Energy Corporation
Dividend Reinvestment and Stock Purchase Plan ("DRSPP"). The
DRSPP is now available to shareholders of record only.
Participants in the DRSPP may have all or part of their dividends
reinvested at a 3% discount from market prices. DRSPP
participants may purchase additional shares of Company common
stock as often as weekly with optional cash payments of at least
$25, up to an annual maximum of $60,000. At September 30, 1994,
712,596 shares were available for future issuance under the plan.
On April 27, 1988, the Company adopted a Shareholders' Rights
Plan (the "Rights Plan") and declared a dividend of one right (a
"Right") for each outstanding pre-split share of common stock of
the Company, payable to shareholders of record as of May 10, 1988.
Each Right will entitle the holder thereof, until the earlier of
May 10, 1998 or the date of redemption of the Rights, to buy one
share of common stock of the Company at an exercise price of $30
per share, subject to adjustment by the Board of Directors upon
the occurrence of certain events. The Rights will be represented
by the common stock certificates and are not exercisable or
transferable apart from the common stock until a "Distribution
Date" (which is defined in the Rights Agreement between the
Company and the Rights Agent as the date upon which the Rights
become separate from the common stock).
At no time will the Rights have any voting rights. The
exercise price payable and the number of shares of common stock or
other securities or property issuable upon exercise of the Rights
are subject to adjustment from time to time to prevent dilution.
Until the Distribution Date, the Company will issue one Right with
each share of common stock that becomes outstanding so that all
shares of common stock will have attached Rights. After a
Distribution Date, the Company may issue Rights when it issues
46<PAGE>
common stock if the Board deems such issuance to be necessary or
appropriate.
The Rights have certain anti-takeover effects and may cause
substantial dilution to a person or entity that attempts to
acquire the Company on terms not approved by the Board of
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 the
Rights become exercisable or transferable, the Rights may be
redeemed by the Company at $.05 per Right.
The Company has had an Incentive Stock Option Plan for key
employees covering an aggregate of 100,000 shares of common stock.
The plan provided for options to be granted at prices not less
than the fair market value of the stock on the date of grant and
to be exercisable over ten years from such date in cumulative
annual installments of 25% of the aggregate shares granted,
commencing one year after the date of grant. At September 30,
1993, no options were outstanding under the plan. The Company
allowed the plan to expire in October 1993 without granting
additional options.
The following table summarizes the status of the expired
Incentive Stock Option Plan as of September 30, 1993 and 1992:
1993 1992
------------------- -------------------
Price Price
Shares per share Shares per share
------------------ ------- -----------
Outstanding options at
beginning of year 6,000 $9.25-10.63 12,750 $9.25-10.63
Exercised (6,000) 9.25-10.63 (6,750) 9.25-10.63
------ ------
Outstanding options
at end of year - - 6,000 9.25-10.63
====== ======
Exercisable options
at end of year - 6,000
Options available for
future grants
(pre-split) 8,150 8,150
The Company's Restricted Stock Grant Plan for management and
key employees of the Company, which became effective October 1,
1987, provides for awards of common stock that are subject to
certain restrictions. The plan is administered by the Board of
Directors. The members of the Board who are not employees of the
Company make the final determinations regarding participation in
the plan, awards under the plan, and restrictions on the re-
stricted stock awarded. The restricted stock may consist of
47<PAGE>
previously issued shares purchased in the open market or shares
issued directly from the Company. The total number of shares of
restricted stock that may be awarded under the plan was increased
to 600,000 shares (900,000 post-split shares) after receiving
shareholder approval in 1993. During 1994, 1993 and 1992,
109,500, 25,500 and 51,750 shares, respectively, were awarded
under the plan. Prior to 1992, 328,950 shares were awarded under
the plan. Related compensation expense of $1,164,000, $735,000
and $673,000 was recognized in 1994, 1993 and 1992, respectively.
At September 30, 1994, 384,300 shares were available for award.
7. Employee retirement and stock ownership plans
At September 30, 1994, the Company had three defined benefit
pension plans. One covers the Western Kentucky Division employ-
ees, one covers the Greeley Gas Division employees, and the third
covers all other Atmos employees. The plans provide essentially
the same benefits to all employees. Benefits are based on years
of service and the employee's compensation during the highest paid
five consecutive calendar years within the last 10 years of
employment. The Company's funding policy is to contribute
annually an amount in accordance with the requirements of the Em-
ployee Retirement Income Security Act of 1974. Contributions are
intended to provide not only for benefits attributed to service to
date but also for those expected to be earned in the future.
The following table sets forth the combined funded status of
the Company's defined benefit retirement plans at June 30, 1994
and 1993 and amounts recognized in the Company's balance sheets at
September 30, 1994 and 1993 for the plans covering all employees
except for employees of the Greeley Gas Division:
1994 1993
--------- ---------
(In thousands)
Actuarial present value of benefit
obligations
Accumulated benefit obligation,
including vested benefits of
$87,906 and $86,141 in 1994
and 1993, respectively $ (89,680) $ (87,006)
========= =========
Projected benefit obligation $(102,223) $(100,214)
Plan assets at fair value 110,864 114,772
--------- ---------
Funded status 8,641 14,558
Unrecognized net asset being
recognized over 13 years (633) (851)
Unrecognized prior service cost 1,423 482
Unrecognized net (gain)/loss 1,883 (2,032)
--------- ---------
Prepaid pension cost $ 11,314 $ 12,157
========= =========
48<PAGE>
Net periodic pension cost for 1994, 1993 and 1992 included
the following components:
1994 1993 1992
-------- -------- --------
(In thousands)
Service cost $ 2,575 $ 2,182 $ 2,117
Interest cost 7,774 7,258 6,783
Actual return on plan assets (631) (15,049) (12,534)
Net amortization and deferral (8,875) 6,316 3,981
-------- -------- --------
Net periodic pension cost $ 843 $ 707 $ 347
======== ======== ========
The weighted-average discount rates used in determining the
actuarial present value of the projected benefit obligation were
8.375% and 7.75% at June 30, 1994 and 1993, respectively. The
rate of increase in future compensation levels reflected in such
determination was 4.5% and 5.0% for the years ended September 30,
1994 and 1993, respectively. The expected long-term rate of
return on assets was 9.5%, 8.5% and 9.0% for the years ended
September 30, 1994, 1993 and 1992, respectively. The plan assets
consist primarily of investments in common stocks, interest
bearing securities and interests in commingled pension trust
funds. Prepaid pension cost is included in deferred charges and
other assets.
49<PAGE>
The following table sets forth the Greeley Gas Division
plan's funded status at September 30, 1994 and 1993:
1994 1993
--------- --------
(In thousands)
Actuarial present value of benefit obligations
Accumulated benefit obligation,
including vested benefits of
$12,849 and $9,959 in 1994
and 1993, respectively $ (13,206) $ (10,088)
========= =========
Projected benefit obligation $ (15,020) $ (13,359)
Plan assets at fair value 13,140 14,204
--------- --------
Funded status (1,880) 845
Unrecognized net asset being
recognized over 15 years (2,100) (2,390)
Unrecognized prior service cost 455 -
Unrecognized net loss 3,186 2,677
--------- --------
(Accrued) prepaid pension cost $ (339) $ 1,132
========= ========
Net periodic pension cost (credit) for the Greeley Gas
Division plan for 1994, 1993 and 1992 included the following
components:
1994 1993 1992
------- ------- -------
(In thousands)
Service cost $ 486 $ 374 $ 385
Interest cost on projected
benefit obligation 1,039 954 952
Actual return on plan assets 441 (1,180) (1,146)
Net amortization and deferral (1,795) (257) (218)
------- ------- -------
Net periodic pension
cost (credit) $ 171 $ (109) $ (27)
======= ======= =======
Accumulated plan benefits were computed using the Projected
Unit Credit funding method. The discount rate and rate of in-
crease in future compensation levels used in determining the
actuarial present value of the projected benefit obligations were
8.375% and 4.5%, respectively, in 1994 and 7.75% and 6.25%,
respectively, in 1993. The expected long-term rate of return on
plan assets was 9.5% and 9.0% in 1994 and 1993, respectively.
Plan assets consist primarily of corporate bonds, equity securit-
ies, mutual funds, partnership interests, and other miscellaneous
investments. The actual return on plan assets in 1994 resulted in
a loss of $.4 million due to writedowns of certain plan assets to
reflect current market value.
50<PAGE>
Effective October 1, 1987, the Company adopted a nonqualified
Supplemental Executive Benefits Plan ("Supplemental Plan") which
provides additional pension benefits to the executive officers and
certain other employees of the Company. Expense recognized in
connection with the Supplemental Plan during fiscal 1994, 1993 and
1992 was $2,062,000, $1,492,000 and $872,000, respectively.
The Company sponsors an Employee Stock Ownership Plan
("ESOP"). Full time employees who have completed one year of
service, as defined in the plan, are eligible to participate.
Each participant enters into a salary reduction agreement with the
Company pursuant to which the participant's salary is reduced by
an amount not less than 2% nor more than 10%. Taxes on the amount
by which the participant's salary is reduced are deferred pursuant
to Section 401(k) of the Internal Revenue Code. The amount of the
salary reduction is contributed by the Company to the ESOP for the
account of the participant. The Company may make a matching
contribution for the account of the participant in an amount
determined each year by the Board of Directors, which amount must
be at least equal to 25% of all or a portion of the participant's
salary reduction. For the 1994 plan year, the Board of Directors
elected to match 100% of each participant's salary reduction
contribution up to 4% of the participant's salary. These matching
percentages have also been approved for the 1995 plan year.
Matching contributions to the ESOP amounted to $1,780,000,
$1,413,000, and $1,324,000 for 1994, 1993 and 1992, respectively.
The Directors may also approve discretionary contributions,
subject to the provisions of the Internal Revenue Code of 1986 and
applicable regulations of the Internal Revenue Service. The
Company recorded a charge of $1,000,000 for a discretionary
contribution in the year ended September 30, 1993. Company
contributions to the plan are expensed as incurred.
Effective January 1, 1988, the Greeley Gas Division adopted a
401(k) plan that covers substantially all the Greeley Gas Division
employees. Employee contributions are limited to 6% of base
compensation. The Company matches 50% of employee contributions.
Total employer contributions to the 401(k) plan were $141,000,
$230,000, and $288,000 for the periods ended September 30, 1994,
1993, and 1992, respectively. Contributions to the plan were
discontinued on March 31, 1994 and participants were enrolled in
the Atmos ESOP on April 1, 1994.
8. Other postretirement benefits
In addition to providing pension benefits, the Company
provides certain other postretirement benefits for retired
employees, the major benefit being health care. To be eligible
for these benefits, an employee must retire under the terms of the
Company's retirement plans. Prior to 1994, the cost of other
postretirement benefits was recognized by expensing claims and
annual insurance premiums as incurred. In fiscal 1993 and 1992,
these costs totaled $1,453,000 and $1,626,000, respectively.
51<PAGE>
Effective October 1, 1993, the Company adopted Financial
Accounting Standards No. 106 ("SFAS No. 106"), "Employers'
Accounting for Postretirement Benefits Other Than Pensions". SFAS
No. 106 focuses principally on postretirement health care benefits
and significantly changed the practice of accounting for post-
retirement benefits on a pay-as-you-go basis by requiring accrual
of such benefit costs at Atmos on an actuarial basis from the date
each employee reaches age 45 until the date of full eligibility
for such benefits. The Company is amortizing on a straight line
basis the initial transition obligation of $33,354,000 over 20
years. The effect of adopting the new rules increased net
periodic postretirement benefit cost for the year ended September
30, 1994 by $3,789,000 and decreased net income for the period by
$2,440,000. Approximately $746,000 of this increased cost was
recovered through rates during 1994.
Atmos sponsors two defined benefit postretirement plans other
than pensions. One plan provides medical, dental, vision and life
insurance benefits to retired employees of Greeley Gas Company.
The other offers medical benefits to all other retired Atmos
employees. Substantially all of the Company's employees may
become eligible for these benefits if they reach retirement age
while working for the Company and attain 10 consecutive years of
service. Participant contributions are required under these
plans. Prior to June 1994, the plans were not funded. In June
1994, the Company made its first quarterly payment to the external
trust set up to fund SFAS No. 106 costs in excess of the pay-as-
you-go cost in Kansas in accordance with an order of the Kansas
Corporation Commission. The amount of funding will ultimately
depend upon the ratemaking treatment allowed in the Company's
various rate jurisdictions.
The components of net periodic postretirement benefit cost
for the year ended September 30, 1994 are as follows (in thou-
sands):
Service cost $1,817
Interest cost 2,269
Amortization of transition obligation 1,668
------
$5,754
======
52<PAGE>
The following is a reconciliation of the funded status of the
plans to the net postretirement benefits liability on the balance
sheet as of September 30, 1994 and October 1, 1993 (in thousands):
1994 1993
-------- --------
Accumulated postretirement benefit obligation
Retirees $(18,083) $(18,237)
Fully eligible employees (6,827) (8,596)
Other employees (4,206) (6,521)
-------- --------
(29,116) (33,354)
Plan assets 274 -
-------- --------
Accumulated postretirement benefit
obligation in excess of plan assets (28,842) (33,354)
Unrecognized prior service cost (2,256) -
Unrecognized net (gain) or loss (4,105) -
Unrecognized transition obligation 31,686 33,354
-------- --------
Accrued postretirement benefits liability $ (3,517) $ -
======== ========
In the latest actuarial calculation of the accrued postre-
tirement benefits liability, the assumed health care cost trend
rate used to estimate the cost of postretirement benefits was
10.5% for the 1993-1994 year, 9.5% for the 1994-1995 year and is
assumed to decrease gradually to 5.0% for 1999-2000 and remain at
that level thereafter. Similarly, the dental trend rate is 8.0%
for the 1993-1994 year and gradually decreases to 7.0% for 1995-
1996 at which time dental benefits will be discontinued. The
trend for vision benefits is assumed to remain level for all years
at 4.5%. The effect of a 1% increase in the assumed health care
cost trend rate for each future year is $410,000 on the annual
aggregate of the service and interest cost components of net
periodic postretirement benefit costs and $2,279,000 on the
accumulated postretirement benefit obligation as of September 30,
1994. The assumed discount rate, the rate at which liabilities
could be settled, was 8.25% and 7.0% as of September 30, 1994 and
1993, respectively.
The Company is currently recovering other postretirement
benefit ("OPEB") costs through its regulated rates on a pay-as-
you-go basis in a majority of its service areas in Texas, Kentucky
and Louisiana. It is allowed to recover OPEB costs in its
remaining service areas under SFAS No. 106 accrual accounting.
The rate recovery of SFAS No. 106 cost by jurisdiction is discuss-
ed below. Management believes that accrual accounting in accor-
dance with SFAS No. 106 is appropriate and will seek rate recovery
of accrual-based expenses in all of its ratemaking jurisdictions.
In May 1993, the Louisiana Commission issued an order for all
utilities under its jurisdiction to continue to use the pay-as-
you-go accounting method for rate treatment of SFAS No. 106 costs.
53<PAGE>
Utilities may apply to the Louisiana Commission for authority to
recognize a regulatory asset to be amortized on a pay-as-you-go
basis to bridge the gap between ratemaking and accounting. The
Louisiana Commission retains the flexibility to examine individual
companies' accounting for SFAS No. 106 costs to determine if
special exceptions to this order are warranted. Recovery of SFAS
No. 106 costs were not allowed in the Company's Rate Stabilization
Clause increase implemented March 1, 1994.
In June 1992, the Kentucky Public Service Commission
("Kentucky Commission") declined a request by a group of utilities
to grant a blanket commitment for the future recovery of SFAS No.
106 costs in excess of pay-as-you-go costs for all utilities. The
Kentucky Commission's order stated that each utility could file an
individual application to seek recovery of such costs. At a
rehearing held in December 1992, the Kentucky Commission affirmed
its initial order.
In May 1993, the Company filed rate requests which included
SFAS No. 106 costs in Fritch and Sanford, Texas and for the
surrounding environs. The rates for the environs are subject to
the jurisdiction of the Railroad Commission of Texas ("Railroad
Commission"). In its order of August 30, 1993, the Railroad
Commission approved recovery of SFAS No. 106 costs and internal
funding.
In September 1994 the Company filed for a rate increase with
its West Texas cities. The rate case, which included SFAS No. 106
costs, was settled with those cities subsequent to September 30,
1994.
In September 1993, GGC filed a rate request for its Colorado
service area which included SFAS No. 106 costs. In May 1994, the
Company began implementing new rates in its Colorado service area.
The new rates increased annual revenues by $3,200,000 and included
recovery of accrual-based SFAS No. 106 costs. By order issued in
October 1994, the Colorado Public Utility Commission approved
recovery of SFAS No. 106 costs with the condition of external
funding of the difference between SFAS No. 106 expense and pay-as-
you-go expense.
By order issued in November 1993, the Kansas Corporation
Commission approved recovery of SFAS No. 106 expenses beginning in
December 1993 with the condition that the difference between
amounts computed as SFAS No. 106 expense and pay-as-you-go expense
shall be remitted quarterly to an external trust fund.
The Company will seek rate recovery of accrual based SFAS No.
106 expenses in its ratemaking jurisdictions that have not yet
approved the recovery of these expenses. The portion of this
additional expense in excess of the pay-as-you-go amount in these
ratemaking jurisdictions that will immediately or ultimately be
allowed in rates cannot presently be determined. The ultimate
impact of the adoption of SFAS No. 106 on the Company's financial
position and results of operations will not be known with certain-
54<PAGE>
ty until the regulatory treatment that will be allowed in each of
the Company's ratemaking jurisdictions is determined.
9. Postemployment benefits
The Company also provides postemployment benefits, primarily
workers' compensation, to former or inactive employees after
employment but before retirement. The Financial Accounting
Standards Board has issued Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment
Benefits" ("SFAS No. 112"), which applies to such benefits and
will be effective for the Company's 1995 fiscal year. Under SFAS
No. 112, employers are required to recognize the obligation to
provide postemployment benefits if certain conditions are met.
Postemployment benefit costs are currently recorded and recovered
in rates on the pay-as-you-go basis. The rate treatment of SFAS
No. 112 accrual based costs has not been determined at this time.
The reduction in future earnings, if any, that would result from
this accrual would be offset to the extent that it is approved to
be recovered in rates. Based on a preliminary actuarial study, the
Company currently estimates that the cumulative effect of impleme-
ntation of SFAS No. 112 and the increase in future annual costs
will not have a material adverse effect on earnings.
10. Supplementary information
Taxes, other than income taxes for 1994, 1993 and 1992
consisted of the following:
1994 1993 1992
------- ------- -------
(In thousands)
Gross receipts $ 7,252 $ 7,312 $ 7,393
Ad valorem 5,124 4,992 4,618
Payroll 3,475 3,353 3,322
Other 957 1,149 1,065
------- ------ -------
$16,808 $16,806 $16,398
======= ======= =======
11. Contingencies
On March 15, 1991, suit was filed in the 15th Judicial
District Court of Lafayette Parish, Louisiana, by the "Lafayette
Daily Advertiser" and others against the Trans La Division, Trans
Louisiana Industrial Gas Company, Inc. ("TLIG"), a wholly owned
subsidiary of the Company, and Louisiana Intrastate Gas Corporati-
on and certain of its affiliates ("LIG"). LIG is the Company's
primary supplier of natural gas in Louisiana and is not otherwise
affiliated with the Company.
The plaintiffs purported to represent a class consisting of
all residential and commercial gas customers in the Trans La
Division's service area. Among other things, the lawsuit alleged
55<PAGE>
that the defendants violated antitrust laws of the state of
Louisiana by manipulating the cost-of-gas component of the Trans
La Division's gas rate to the purported customer class, thereby
causing such purported class members to pay a higher rate. The
plaintiffs made no specific allegation of an amount of damages.
The defendants brought an appeal to the Louisiana Supreme
Court of rulings by the trial court and the Third Circuit Court of
Appeal which denied defendants' exceptions to the jurisdiction of
the trial court. It was the position of the defendants that the
plaintiffs' claims amount to complaints about the level of gas
rates and should be within the exclusive jurisdiction of the
Louisiana Commission.
On January 19, 1993, the Louisiana Supreme Court issued a
decision reversing in part the lower courts' rulings, dismissing
all of plaintiffs' claims against the defendants which seek
damages due to alleged overcharges and further ruling that all
such claims are within the exclusive jurisdiction of the Louisiana
Commission. Any claims which seek damages other than overcharges
were remanded to the trial court but were stayed pending the
completion of the Louisiana Commission proceeding referred to
below.
The Louisiana Commission has instituted a docketed proceeding
for the purpose of investigating the costs included in the Trans
La Division's purchased gas adjustment component of its rates.
Both the Trans La Division and LIG are parties to the proceeding.
Much of the discovery in this proceeding has been conducted and a
procedural schedule has been established. The Company believes the
allegations as they relate to the Company, whether brought in
court or at the Louisiana Commission, are without merit, and that
the chances of a material adverse outcome are remote. The Company
will continue to vigorously protect its interest in this matter.
From time to time, claims are made and lawsuits are filed
against the Company arising out of the ordinary business of the
Company. In the opinion of the Company's management, liabilities,
if any, arising from these actions are either covered by
insurance, adequately reserved for by the Company or would not
have a material adverse effect on the financial condition of the
Company.
12. Statement of cash flows
Supplemental disclosures of cash flow information for 1994,
1993 and 1992 are presented below:
56<PAGE>
1994 1993 1992
------- ------- -------
(In thousands)
Cash paid for
Interest $12,756 $13,436 $14,496
Income taxes 6,352 8,190 3,754
13. Leases
The Company has entered into noncancelable leases involving
office space and warehouse space. The remaining lease terms range
from one to 20 years and generally provide for the payment of
taxes, insurance and maintenance by the lessee. Net property,
plant and equipment included amounts for capital leases of
$5,664,000 and $6,029,000 at September 30, 1994 and 1993,
respectively.
The related future minimum lease payments at September 30,
1994 were as follows:
Capital Operating
leases leases
-------- --------
(In thousands)
1995 $ 1,716 $ 5,071
1996 1,717 4,817
1997 1,683 3,808
1998 1,628 2,958
1999 1,504 3,036
Thereafter 11,297 23,335
------- -------
Total minimum lease payments 19,545 43,025
Less amount representing
contingent payments from
increases in the Consumer
Price Index (946) (20)
------- -------
Net minimum lease payments 18,599 $43,005
=======
Less amount representing interest (12,305)
-------
Present value of net minimum
lease payments $ 6,294
=======
Consolidated rent expense amounted to $6,490,000, $5,277,000
and $5,395,000 for fiscal 1994, 1993 and 1992, respectively.
Rents are expensed and recovered in rates on a pay-as-you-go
basis.
57<PAGE>
SUPPLEMENTARY DATA
Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data are presented
below. The sum of net income per share by quarter may not equal
the net income per share for the year due to variations in the
weighted average shares outstanding used in computing such
amounts.
<TABLE>
<CAPTION>
Quarter ended
----------------------------------------------------------------------------------
December 31, March 31, June 30, September 30,
----------------- ----------------- ----------------- -----------------
1993 1992 1994 1993 1994 1993 1994 1993
-------- -------- -------- -------- -------- -------- -------- --------
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $145,501 $130,700 $186,944 $166,238 $ 90,013 $ 91,219 $ 77,350 $ 71,484
Gross profit 48,421 42,638 59,366 58,606 31,790 34,463 28,660 27,402
Operating income (loss) 10,302 9,730 16,345 16,877 1,433 3,847 (1,614) (177)
Net income (loss) 7,088 6,765 13,242 13,760 (1,224) 831 (4,427) (3,812)
Net income (loss) per
share .47 .48 .87 .97 (.08) .06 (.29) (.26)
</TABLE>
58<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding directors is incorporated herein by
reference from the Company's definitive proxy statement for the
annual meeting of shareholders on February 8, 1995.
Information regarding executive officers is included in Part
I.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated herein by reference from the Company's
definitive proxy statement for the annual meeting of shareholders
on February 8, 1995.
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 8, 1995.
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 8, 1995.
59<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 financial statements and financial statement schedules
listed in the accompanying Index to Financial Statements and
Financial Statement Schedules are filed as part of this annual
report.
3. Exhibits
The exhibits listed in the accompanying Exhibits Index are
filed as part of this annual report. The exhibits numbered
10.18(a) through 10.26(c) are management contracts or compensatory
plans or arrangements.
(b) Reports on Form 8-K
None.
60<PAGE>
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
(Item 8, 14(a) 1 and 2)
Page
Number
Financial statements:
Consolidated balance sheets at September 30,
1994 and 1993 31
Consolidated statements of income for the
years ended September 30, 1994, 1993 and 1992 32
Consolidated statements of shareholders' equity
for the years ended September 30, 1994, 1993 and 1992 33
Consolidated statements of cash flows for the years
ended September 30, 1994, 1993 and 1992 34
Notes to consolidated financial statements 36-56
Independent auditors' report 30
Financial statement schedules for the years
ended September 30, 1994, 1993 and 1992:
V - Property, plant and equipment 61
VI - Accumulated depreciation and amortization
of property, plant and equipment 62
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.
61<PAGE>
ATMOS ENERGY CORPORATION
SCHEDULE V
PROPERTY, PLANT AND EQUIPMENT
Balance at Retire- Balance
beginning Additions ments at end of
of year at cost or sales year
--------- --------- -------- ---------
(In thousands)
Year ended
September 30, 1994:
Utility plant $496,153 $49,544 $7,863 $537,834
Construction
in progress 5,359 811 312 5,858
-------- ------- ------ --------
$501,512 $50,355 $8,175 $543,692
======== ======= ====== ========
Year ended
September 30, 1993:
Utility plant $458,548 $41,824 $4,219 $496,153
Construction
in progress 4,065 1,319 25 5,359
-------- ------- ------ --------
$462,613 $43,143 $4,244 $501,512
======== ======= ====== ========
Year ended
September 30, 1992:
Utility plant $421,048 $41,613 $4,113 $458,548
Construction
in progress 3,519 556 10 4,065
-------- ------- ------ --------
$424,567 $42,169 $4,123 $462,613
======== ======= ====== ========
Depreciation is provided at various rates on a straight-line basis
over the estimated useful lives of the assets. Such rates range
from 2% to 33% per year with the average rate currently being
approximately 3.5% per year.
62<PAGE>
ATMOS ENERGY CORPORATION
SCHEDULE VI
ACCUMULATED DEPRECIATION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Additions Deductions
Balance charged to
at to retirements, Balance
beginning costs and renewals and at end
of year expenses replacements of year
--------- --------- ------------ -------
(In thousands)
Year ended
September 30, 1994:
Utility plant $202,237 $20,317 $ 6,269 $216,285
Year ended
September 30, 1993:
Utility plant $185,689 $19,857 $ 3,309 $202,237
Year ended
September 30, 1992:
Utility plant $165,380 $21,803 $ 1,494 $185,689
63<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/ JAMES F. PURSER
-----------------------
James F. Purser
Executive Vice President and
Chief Financial Officer
Date: December 15, 1994
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose
signature appears below hereby constitutes and appoints James F.
Purser, his true and lawful attorney-in-fact and agent, 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/ CHARLES K. VAUGHAN Chairman of December 15, 1994
------------------------- the Board
Charles K. Vaughan
/s/ RONALD L. FANCHER President and December 15, 1994
------------------------- Chief Executive
Ronald L. Fancher Officer
64<PAGE>
/s/ JAMES F. PURSER Executive Vice December 15, 1994
------------------------- President and
James F. Purser Chief Financial
Officer
/s/ DAVID L. BICKERSTAFF Vice President December 15, 1994
------------------------- and Controller
David L. Bickerstaff (Principal
accounting officer)
/s/ TRAVIS W. BAIN, II Director December 15, 1994
-------------------------
Travis W. Bain, II
/s/ DAN BUSBEE Director December 15, 1994
-------------------------
Dan Busbee
/s/ PHILLIP E. NICHOL Director December 15, 1994
-------------------------
Phillip E. Nichol
/s/ JOHN W. NORRIS, JR. Director December 15, 1994
-------------------------
John W. Norris, Jr.
/s/ CARL S. QUINN Director December 15, 1994
-------------------------
Carl S. Quinn
/s/ LEE E. SCHLESSMAN Director December 15, 1994
-------------------------
Lee E. Schlessman
/s/ RICHARD WARE II Director December 15, 1994
-------------------------
Richard Ware II
/s/ DEWEY G. WILLIAMS Director December 15, 1994
-------------------------
Dewey G. Williams
65<PAGE>
EXHIBITS INDEX
Item 14. (a) (3)
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
3.1 Restated Articles of Incorporation Exhibit (3)(a) of Form
dated November 10, 1989 10-K for fiscal year
ended September 30, 1991
3.2 By-Laws of Atmos Energy Corporation Exhibit (3) of Form 10-Q
(Amended and restated as of May 11, for quarter ended June
1994) 30, 1994
4.1 Specimen Common Stock Certificate Exhibit (4) of the
(Energas Company) October 28, 1983 Form 10
(File No. 0-11249)
4.2 Specimen Common Stock Certificate Exhibit (4) (b) of Form
(Atmos Energy Corporation) 10-K for fiscal year
ended September 30, 1988
(File No. 1-10042)
4.3(a) Rights Agreement, dated as of April Exhibit (1) of Form 8-K
27, 1988, between the Company and filed May 10, 1988 (File
Morgan Shareholder Services Trust No. 0-11249)
Company
4.3(b) Amendment No. 1 to Rights Agreement,
dated August 10, 1994
4.3(c) Certificate of Adjusted Price, dated
August 15, 1994
9 Not applicable
10.1(a) Note Purchase Agreement, dated Exhibit (10)(a)(i) of
December 30, 1986, by and between Form 10-K for fiscal year
the Company and John Hancock Mutual ended September 30, 1991
Life Insurance Company
Note Purchase Agreement, dated
December 30, 1986, by and between
the Company and Mellon Bank, N.A.,
Trustee under Master Trust Agreement
of NYNEX Corporation dated January
1, 1984 for Employee Pension Plans -
NYNEX - John Hancock - Private
Placement. (Agreement is identical
to the Hancock Agreement listed
above except as to the parties
thereto.)
66<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.1(b) Letter, dated November 13, 1987, Exhibit 28(a) of Form 8-K
from John Hancock Mutual Life filed January 7, 1988
Insurance Company to the Company (File No. 0-11249)
Letter, dated November 13, 1987,
from Mellon Bank, N.A., Trustee
under Master Trust Agreement of
NYNEX Corporation dated January 1,
1984 for Employee Pension Plans -
NYNEX - John Hancock - Private
Placement to the Company (Mellon
letter is identical to the Hancock
letter listed above except as to the
parties thereto.)
10.1(c) Amendment to Note Purchase Exhibit (10)(a)(iii) of
Agreement, dated October 11, 1989, Form 10-K for fiscal year
by and between the Company and John ended September 30, 1989
Hancock Mutual Life Insurance (File No. 1-10042)
Company revising Note Purchase
Agreement dated December 30, 1986
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 NYNEX
Corporation dated January 1, 1984
for Employee Pension Plans - NYNEX -
John Hancock - Private Placement
revising Note Purchase Agreement
dated December 30, 1986. (This
amendment is identical to the
Hancock amendment listed above
except as to the parties thereto.)
10.1(d) Amendment to Note Purchase Exhibit (10)(a)(iv) of
Agreement, dated November 12, 1991, Form 10-K for fiscal year
by and between the Company and John ended September 30, 1991
Hancock Mutual Life Insurance
Company revising Note Purchase
Agreement dated December 30, 1986.
67<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
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 NYNEX
Corporation dated January 1, 1984
for Employee Pension Plans - NYNEX -
John Hancock - Private Placement
revising Note Purchase Agreement
dated December 30, 1986. (This
amendment is identical to the
Hancock amendment listed above
except as to the parties thereto.)
10.2(a) Note Purchase Agreement, dated as of Exhibit 10(c) of Form 8-K
December 21, 1987, by and between filed January 7, 1988
the Company and John Hancock Mutual (File No. 0-11249)
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.)
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.)
10.2(b) Amendment to Note Purchase Exhibit (10)(b)(ii) of
Agreement, dated October 11, 1989, Form 10-K for fiscal year
by and between the Company and John ended September 30, 1989
Hancock Mutual Life Insurance (File No. 1-10042)
Company revising Note Purchase
Agreement dated December 21, 1987
68<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
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.)
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.)
10.2(c) Amendment to Note Purchase Exhibit 10(b)(iii) of
Agreement, dated November 12, 1991, Form 10-K for fiscal year
by and between the Company and John ended September 30, 1991
Hancock Mutual Life Insurance
Company 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.)
69<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
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.)
10.3(a) Note Purchase Agreement, dated as of Exhibit 10(c) of Form 10-
October 11, 1989, by and between the K for fiscal year ended
Company and John Hancock Mutual Life September 30, 1989 (File
Insurance Company No. 1-10042)
10.3(b) Amendment to Note Purchase Exhibit 10(c)(ii) of Form
Agreement, dated as of November 12, 10-K for fiscal year
1991, by and between the Company and ended September 30, 1991
John Hancock Mutual Life Insurance
Company revising Note Purchase
Agreement dated October 11, 1989
10.4(a) Note Purchase Agreement, dated as of Exhibit 10(f)(i) of Form
August 29, 1991, by and between the 10-K for fiscal year
Company and The Variable Annuity ended September 30, 1991
Life Insurance Company
10.4(b) Amendment to Note Purchase Exhibit 10(f)(ii) of Form
Agreement, dated November 26, 1991, 10-K for fiscal year
by and between the Company and The ended September 30, 1991
Variable Annuity Life Insurance
Company revising Note Purchase
Agreement dated August 29, 1991
10.5 Note Purchase Agreement, dated as of Exhibit (10)(f) of Form
August 31, 1992, by and between the 10-K for fiscal year
Company and The Variable Annuity ended September 30, 1992
Life Insurance Company
10.6(a) Service Agreement No. 50,772 between
Greeley Gas Company and Public
Service Company of Colorado (West
Gas Supply Co. prior to merger with
PSCO) dated August 1, 1992
70<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.6(b) Transportation Storage Service
Agreement No. TA-0544 between
Greeley Gas Company and Williams
Natural Gas Company dated October 1,
1993
10.6(c) No-Notice Transportation Service
Agreement No. 31013, Rate Schedule
NNT-1, between Greeley Gas Company
and Colorado Interstate Gas Company,
as amended, dated October 1, 1993
10.6(d) Firm Transportation Service
Agreement No. 35009, Rate Schedule
TF2, between Greeley Gas Company and
Colorado Interstate Gas Company, as
amended, dated October 1, 1993
10.7(a) Amarillo Supply Agreement dated
January 2, 1993 between the Company
and Mesa Operating Company
10.7(b) Interruptible Gas Transportation and Exhibit (10)(g)(iv) of
Sales Agreement dated January 1, Form 10-K for fiscal year
1991, between Mesa Operating Limited ended September 30, 1992
Partnership and Energas Company
regarding transportation charges to
Mesa
10.7(c) Letter agreement between the Company Exhibit (10)(h)(vi) of
and Mesa Operating Limited Form 10-K for fiscal year
Partnership dated March 21, 1989, ended September 30, 1989
regarding transportation rates (File No. 1-10042)
10.8(a) Gas Sales Agreement between the Exhibit (10)(i)(i) of
Company and Westar Transmission Form 10-K for fiscal year
Company dated January 1, 1986, as ended September 30, 1989
amended by Letter Agreement dated (File No. 1-10042)
November 21, 1986, and Agreement
dated December 9, 1988, revising the
pricing formula for city gate sales
10.8(b) Amendment to Gas Sales Agreement, Exhibit (10)(h)(ii) of
dated February 27, 1987, between the Form 10-K for fiscal year
Company and Westar Transmission ended September 30, 1992
Company
10.8(c) Amendment to Gas Sales Agreement, Exhibit (10)(h)(iii) of
dated January 1, 1988, between Cabot Form 10-K for fiscal year
Gas Supply Corporation ("CGSC") and ended September 30, 1992
the Company
71<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.9(a) Gas Transportation Agreement between Exhibit 10(i)(i) of Form
the Company and Westar Transmission 10-K for fiscal year
Company dated January 1, 1986, as ended September 30, 1991
amended by letter agreement dated
November 21, 1986
10.9(b) Amendment to Gas Transportation Exhibit (10)(i)(ii) of
Agreement, dated January 1, 1988, Form 10-K for fiscal year
between CGSC and the Company ended September 30, 1992
10.10 Supplemental Gas Sales Agreement, Exhibit (10)(j) of Form
dated January 1, 1988, between CGSC 10-K for fiscal year
and the Company ended September 30, 1992
10.11 Gas Purchase and Sales Agreement, Exhibit (10)(k) of Form
dated January 1, 1988, between Cabot 10-K for fiscal year
Energy Marketing Corporation and ended September 30, 1992
EnerMart, Inc.
10.12 Gas Sales Agreement, dated January Exhibit (10)(l) of Form
1, 1988, between the Company and Gas 10-K for fiscal year
Marketing, Inc. ("GMI"), relating to ended September 30, 1992
Amarillo supplemental supplies
10.13 Gas Sales Agreement, dated January Exhibit (10)(m) of Form
1, 1988, between the Company and 10-K for fiscal year
GMI, relating to West Texas ended September 30, 1992
supplemental supplies
10.14 Settlement Agreement, dated January Exhibit (10)(n) of Form
15, 1988, between CGSC and the 10-K for fiscal year
Company ended September 30, 1992
10.15(a) Agreement for Natural Gas Service Exhibit 10(o)(ii) of Form
for Distribution and Resale between 10-K for fiscal year
Trans La and LIG dated October 28, ended September 30, 1991
1991
10.15(b) Agreement for Intrastate Exhibit 10(o)(iii) of
Transportation of Natural Gas Form 10-K for fiscal year
between Trans La and LIG dated ended September 30, 1991
October 28, 1991
10.16(a) Gas Transportation Agreement between Exhibit 10.1 of Form 10-Q
Texas Gas Transmission Corporation for quarter ended
("Texas Gas") and Western Kentucky December 31, 1993
Gas Company, a division of Atmos
Energy Corporation ("Western Ken-
tucky") dated November 1, 1993
(Contract no. T3817, zone 2)
72<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.16(b) Gas Transportation Agreement between Exhibit 10.2 of Form 10-Q
Texas Gas and Western Kentucky dated for quarter ended
November 1, 1993 (Contract no. December 31, 1993
T3770, zone 2)
10.16(c) Gas Transportation Agreement between Exhibit 10.3 of Form 10-Q
Texas Gas and Western Kentucky Gas for quarter ended
dated November 1, 1993 (Contract no. December 31, 1993
T3355, zone 3)
10.16(d) Gas Transportation Agreement between Exhibit 10.4 of Form 10-Q
Texas Gas and Western Kentucky Gas for quarter ended
dated November 1, 1993 (Contract no. December 31, 1993
T3819, zone 4)
10.16(e) Gas Transportation Agreement between Exhibit 10.5 of Form 10-Q
Texas Gas and Western Kentucky Gas for quarter ended
dated November 1, 1993 (Contract no. December 31, 1993
N0210, zone 2, Contract no. N0340,
zone 3, Contract no. N0435, zone 4)
10.17(a) Gas Transportation Agreement, Exhibit 10.17(a) of Form
Contract No. 2550, dated September 10-K for fiscal year
1, 1993, between Tennessee Gas ended September 30, 1993
Pipeline Company, a division of
Tenneco, Inc. ("Tennessee Gas"), and
Western Kentucky, Campbellsville
Service Area
10.17(b) Gas Transportation Agreement, Exhibit 10.17(b) of Form
Contract No. 2546, dated September 10-K for fiscal year
1, 1993, between Tennessee Gas and ended September 30, 1993
Western Kentucky, Danville Service
Area
10.17(c) Gas Transportation Agreement, Exhibit 10.17(c) of Form
Contract No. 2385, dated September 10-K for fiscal year
1, 1993, between Tennessee Gas and ended September 30, 1993
Western Kentucky, Greensburg et al
Service Area
10.17(d) Gas Transportation Agreement, Exhibit 10.17(d) of Form
Contract No. 2551, dated September 10-K for fiscal year
1, 1993, between Tennessee Gas and ended September 30, 1993
Western Kentucky, Harrodsburg
Service Area
73<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.17(e) Gas Transportation Agreement, Exhibit 10.17(e) of Form
Contract No. 2548, dated September 10-K for fiscal year
1, 1993, between Tennessee Gas and ended September 30, 1993
Western Kentucky, Lebanon Service
Area
10.18(a) *Employment Agreement amended and Exhibit 10(r)(i) of Form
restated as of August 8, 1991, 10-K for fiscal year
between the Company and Charles K. ended September 30, 1991
Vaughan
10.18(b) *Employment Agreement amended and Exhibit 10(r)(ii) of Form
restated as of August 8, 1991, 10-K for fiscal year
between the Company and Robert F. ended September 30, 1991
Stephens
10.18(c) *Employment Agreement amended and Exhibit 10(r)(iii) of
restated as of August 8, 1991, Form 10-K for fiscal year
between the Company and Don E. James ended September 30, 1991
10.18(d) *Employment Agreement amended and Exhibit 10(r)(iv) of Form
restated as of August 8, 1991, 10-K for fiscal year
between the Company and James F. ended September 30, 1991
Purser
10.18(e) *Employment Agreement dated March 1, Exhibit 10.1 of Form 10-Q
1993, between the Company and Ronald for quarter ended March
L. Fancher 31, 1993
10.18(f) *Employment Agreement dated August Exhibit 10.18(g) of Form
11, 1993, between the Company and 10-K for fiscal year
H.F. Harber ended September 30, 1993
10.19 *1983 Incentive Stock Option Plan of Exhibit 10(u) of Form 10-
Energas Company K for fiscal year ended
September 30, 1990
10.20 *The Atmos Energy Corporation Exhibit (10)(t) of Form
Supplemental Executive Benefits 10-K for fiscal year
Plan, effective October 1, 1987, ended September 30, 1992
Restated as of November 11, 1992
10.21(a) *The Atmos Energy Corporation Exhibit (10)(u) of Form
Restricted Stock Grant Plan, 10-K for fiscal year
effective October 1, 1987, amended ended September 30, 1992
and restated as of May 13, 1992
10.21(b) *Amendment No. 1 to the Atmos Energy Exhibit 10.1 of Form 10-Q
Corporation Restricted Stock Grant for the quarter ended
Plan (Restated as of May 13, 1992) December 31, 1992
74<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.21(c) *Amendment No. 2 to the Atmos Energy Exhibit 10 of Form 10-Q
Corporation Restricted Stock Grant for the quarter ended
Plan (Restated as of May 13, 1992) June 30, 1993
10.21(d) *Amendment No. 3 to the Atmos Energy Exhibit 10.21(d) of Form
Corporation Restricted Stock Grant 10-K for fiscal year
Plan (Restated as of May 13, 1992) ended September 30, 1993
10.22 *Atmos Energy Corporation Annual Exhibit 10(x) of Form 10-
Performance Bonus Plan for Corporate K for fiscal year ended
Officers, restated as of November 8, September 30, 1990
1989
10.23(a) *Atmos Energy Corporation Mini-Med Exhibit 10(w)(i) of Form
Plan, as restated effective April 1, 10-K for fiscal year
1989 ended September 30, 1992
10.23(b) *Amendment No. 1 to the Atmos Energy Exhibit (10)(w)(ii) of
Corporation Mini-Med Plan Form 10-K for fiscal year
ended September 30, 1992
10.23(c) *Amendment No. 2 to the Atmos Energy Exhibit (10)(w)(iii) of
Corporation Mini-Med Plan Form 10-K for fiscal year
ended September 30, 1992
10.23(d) *Amendment No. 3 to the Atmos Energy Exhibit 10(w)(iv) of Form
Corporation Mini-Med Plan 10-K for fiscal year
ended September 30, 1992
10.23(e) *Amendment No. 4 to the Atmos Energy Exhibit 10.23(e) of Form
Corporation Mini-Med Plan 10-K for fiscal year
ended September 30, 1993
10.24 *Atmos Energy Corporation Deferred Exhibit 10(x) of Form 10-
Compensation Plan for Outside K for fiscal year ended
Directors September 30, 1992
10.25 *Atmos Energy Corporation Retirement Exhibit 10(y) of Form 10-
Plan for Outside Directors K for fiscal year ended
September 30, 1992
10.26(a) *Description of Car Allowance Exhibit 10.26(a) of Form
Payments 10-K for fiscal year
ended September 30, 1993
10.26(b) *Description of Financial and Estate Exhibit 10.26(b) of Form
Planning Program 10-K for fiscal year
ended September 30, 1993
10.26(c) *Description of Sporting Events Exhibit 10.26(c) of Form
Program 10-K for fiscal year
ended September 30, 1993
75<PAGE>
Page Number or
Exhibit Incorporation by
Number Description Reference to
-------- ------------------------------------ -------------------------
10.27(a) Seventh Supplemental Indenture, Exhibit 10.1 of Form 10-Q
dated as of October 1, 1983 between for quarter ended June
Greeley Gas Company ("The Greeley 30, 1994
Gas Division") and the Central Bank
of Denver, N.A. ("Central Bank")
10.27(b) Ninth Supplemental Indenture, dated Exhibit 10.2 of Form 10-Q
as of April 1, 1991, between The for quarter ended June
Greeley Gas Division and Central 30, 1994
Bank
10.27(c) Bond Purchase Agreement, dated as of Exhibit 10.3 of Form 10-Q
April 1, 1991, between The Greeley for quarter ended June
Gas Division and Central Bank 30, 1994
10.27(d) Tenth Supplemental Indenture, dated Exhibit 10.4 of Form 10-Q
as of December 1, 1993, between the for quarter ended June
Company and Colorado National Bank, 30, 1994
formerly Central Bank
11 Not applicable
12 Not applicable
13 Not applicable
16 Not applicable
18 Not applicable
21 Subsidiaries of the registrant Exhibit 22 of Form 10-K
for fiscal year ended
September 30, 1992
22 Not applicable
23 Consent of independent auditors
24 Power of Attorney Signature page of Form
10-K for fiscal year
ended September 30, 1994
27 Financial Data Schedule for Atmos
for year ended September 30, 1994
28 Not applicable
99 Not applicable
_________________________
* This exhibit constitutes a "management contract or compensatory
plan, contract, or arrangement."
76 <PAGE>
EXHIBIT 4.3(b)
AMENDMENT NO. 1 TO RIGHTS AGREEMENT
WHEREAS, Atmos Energy Corporation ("Atmos") and First
National Bank of Boston ("Bank of Boston") are parties to that
certain Rights Agreement dated April 27, 1988 (the "Rights
Agreement"); and
WHEREAS, Atmos and the Bank of Boston desire to amend the
Rights Agreement;
NOW, THEREFORE, effective as of August 10, 1994, the Rights
Agreement is hereby revised and amended in the following
respects;
1. Section 11(a)(i) is amended by adding the following
language at the end of the first sentence of such Section:
"; provided, however, that if the record date
for any such dividend, subdivision,
combination or reclassification shall occur
prior to the Distribution Date, the Company
shall make an appropriate adjustment to the
Purchase Price (taking into account any
additional Rights which may be issued as a
result of such dividend, subdivision,
combination or reclassification), in lieu of
adjusting (as described above) the number of
Common Shares (or other capital shares, as
the case may be) issuable upon exercise of
the Rights."
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment No. 1 to be duly executed and their respective
corporate seals to be hereunto affixed and attested, all as of
August 10, 1994.
ATMOS ENERGY CORPORATION
ATTEST:
BY: /s/ Glen A. Blanscet By: /s/ Ronald L. Fancher
-------------------------- --------------------------
Glen A. Blanscet, Secretary Ronald L. Fancher, President
and Chief Executive Officer
FIRST NATIONAL BANK OF BOSTON
ATTEST:
BY: /s/ David Cosden By: /s/ Colleen H. Shea
--------------------------- --------------------------<PAGE>
EXHIBIT 4.3(c)
CERTIFICATE OF ADJUSTED PRICE
Pursuant to Section 12 of that certain Rights Agreement
dated as of April 27, 1988 (the "Rights Agreement") by and
between Atmos Energy Corporation (successor to Energas Company)
("Company") and First National Bank of Boston (successor in
interest to Morgan Shareholder Services Trust Company) (the
"Rights Agent"), the Company does hereby make the following
certification:
1. As of May 16, 1994, The Company
completed a three-for-two split of its common
stock, effected in the form of a stock
dividend.
2. Pursuant to Section 11(a)(i) of the
Rights Agreement, as amended, the Purchase
Price for each share of common stock pursuant
to the exercise of a Right must be adjusted
to reflect such stock split.
3. The Purchase Price has been adjusted
from $45 per share to $30 per share.
Executed this 15th day of August, 1994.
ATMOS ENERGY CORPORATION
ATTEST:
/s/ Glen A. Blanscet By: Don E. James
--------------------------- ------------------------
Glen A. Blanscet, Secretary Don E. James
Sr. Vice President and
General Counsel<PAGE>
EXHIBIT 10.6(a)
WestGas Document No. 50772
SERVICE AGREEMENT
THIS AGREEMENT made and entered into as of this 2nd day of
October, 1992, by and between WESTERN GAS SUPPLY COMPANY (Seller)
and GREELEY GAS COMPANY (Buyer);
WITNESSETH: That the parties hereto in consideration of the
covenants and payments herein set forth, do mutually covenant and
agree as follows:
1. SALE AND PURCHASE
Seller agrees to sell and deliver and Buyer agrees to
receive, purchase and pay for natural gas under the rate
schedules, at the points of delivery and under the terms and
conditions as herein set forth.
2. VOLUMETRIC OBLIGATIONS
Volumes in MCF
@ Billing Pressure
p.s.i.a. and 60 deg. F.
------------------
Demand Volumes
--------------
Contract Demand 38,007
Peaking Service Demand 7,943
Annual Volumes
--------------
Peaking Service Capacity Volumes 72,000
Total Annual Volumes 5,240,000
3. POINTS OF DELIVERY, MAXIMUM VOLUME OBLIGATIONS AND PRESSURES
Maximum Maximum Assumed
Delivery Delivery Atmospheric Billing
Pressure Obligation Pressure Pressure
Location P.S.I.G. MCF/day (psia) (psia)
See Attached Exhibit "B" - Greeley Eastern <PAGE>
4. APPLICABLE RATE SCHEDULE
The natural gas delivered hereunder shall be paid for by
Buyer under Seller's Rate Schedule CG and CPS, or any superseding
rate schedule or schedules, on file and in effect from time to
time with The Public Utilities Commission of the State of
Colorado (Commission). This agreement in all respects shall be
subject to the provisions of such rate schedule or schedules and
to the applicable provisions of Seller's General Terms and
Conditions of service on file and in effect from time to time
with said Commission, all of which are available for inspection
by Buyer and are made a part hereof by reference.
5. TERM
This agreement shall become effective August 1, 1992, and
continue and remain in force and effect for a primary term ending
September 30, 1995.
This agreement shall continue after the expiration of said
primary term for additional periods of five (5) years each,
unless written notice is given not later than two (2) years prior
to the expiration of said primary term by either party to the
other of its desire to cancel this agreement at the end of said
primary term, or at the end of any such five (5) year period by
notice given not later than two (2) years prior to the expiration
of such five (5) year period.
6. CANCELLATION OF PRIOR CONTRACTS
When this agreement becomes effective, it supersedes and
cancels the following contracts or service agreements between the
parties hereto:
Service Agreement dated November 16, 1986, WestGas Document
No. 50772.
7. BILLING PERIOD
The billing period for gas purchased under this agreement
shall be from the 1st day of one month to the 1st day of the next
succeeding month; provided, however, that Seller reserves to
itself the right to change such billing period upon the giving of
not less than thirty (30) days notice to Buyer.
8. CHANGES
Nothing in this agreement, either expressed or implied,
shall prohibit such future changes in the rate, terms or
conditions under which service is rendered as may become
applicable to the sale of gas hereunder in accordance with law.<PAGE>
9. CONDITIONS OF SERVICE
(a) Minimum Charges: The Demand Charge of the CG rate plus
the Peaking Service Demand Charge and Peaking Capacity Charge of
the CPS rate.
(b) Billing: On or before the tenth (10th) day of each
month, Seller shall render to Buyer a statement of the quantities
of natural gas delivered to Buyer during the preceding billing
period and the amount due from Buyer to Seller. When information
necessary for billing purposes is in control of Buyer, Buyer
shall furnish such information to Seller on or before the twenty-
eighth (29th) day of each month.
(c) Payment: On or before the twentieth (20th) day of each
month, Buyer shall pay Seller, at the location designated on the
billing statement, the amount due from Buyer for the Preceding
billing period as billed by Seller.
(d) Seller odorizes its natural gas only to meet require-
ments of the Department of Transportation, as stated in the
Transportation of Natural and Other Gas by Pipeline, Minimum
Safety Standards, Part 192.625. Seller assumes no responsibility
for odorization of the natural gas after its delivery to Buyer
and it is agreed that Buyer shall not rely on Seller's
odorization of the natural gas to meet any requirement or duty
imposed on Buyer with respect to the odorization of natural gas.
Buyer agrees to indemnify Seller from claims arising out of
injury, death or damage from gas after its delivery to Buyer
based upon lack of or inadequate odorization of the gas.
10. ASSIGNMENT
This agreement may be assigned by either of the parties
hereto to:
(a) Any person, firm or corporation acquiring all, or
substantially all, of the business of said party; or
(b) A trustee or trustees, individual or corporate, as
security for bonds or other obligations or securities;
but it may not be otherwise assigned without the consent of
the other party hereto. Any assignment by Buyer shall not
be effective, and Buyer shall remain liable to pay for all
gas delivered hereunder, until Seller receives a written
statement, executed by the assignee, agreeing to assume all
of Buyer's obligations hereunder.
Except as above restricted, this agreement shall be binding
upon and inure to the benefit of the successors and assignees of
each of the parties hereto.<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this
agreement to be duly signed by their respective officers the day
and year first above written.
TRANSPORTER: WESTERN GAS SUPPLY
COMPANY
Witness/Attest:
By /s/ Linn T. Leeburg
----------------------------
Linn T. Leeburg
Executive Vice President
/s/
- ----------------------------
Assistant Secretary Taxpayer I.D. Number 84-6015506
SHIPPER: GREELEY GAS COMPANY
Witness/Attest:
By /s/ Richard W. Remley
----------------------------
Richard W. Remley
----------------------------
Name
Senior Vice President
----------------------------
Title
/s/ September 28, 1992
- ---------------------------- ----------------------------
Dated
WestGas Document No. 50772 Taxpayer I.D. Number 84-1152755 <PAGE>
Exhibit "B" Effective August 1, 1992
Supersedes
Exhibit "B" Effective May 26, 1986
POINTS OF DELIVERY, MAXIMUM DAILY VOLUME
OBLIGATIONS AND PRESSURES
Maximum Maximum Assumed
Delivery Delivery Atmospheric Billing
Pressure Obligation Pressure Pressure
Location P.S.I.G. MCF/day (psia) (psia)
Ault T. B. Station 45 850 12.29 14.65
Corsey 35 95 12.27 14.65
E. Keenesburg 100 105 12.27 14.65
Eaton 100 2,200 12.37 14.65
Gilcrest 60 550 12.37 14.65
Hill-N-Park 60 270 12.37 14.65
Hudson 40 400 12.27 14.65
Keenesburg 40 340 12.27 14.65
Kersey 125 1,050 12.43 14.65
La Salle 45 1,200 12.40 14.65
Lucerne 45 700 12.37 14.65
Monfort Fed Lots #2 70 650 12.39 14.65
North Greeley 175 16,000 12.39 14.65
Nunn 40 150 12.20 14.65
Pierce 70 400 12.24 14.65
Platteville 50 750 12.32 14.65
Prospect Valley 60 100 12.33 14.65
Roggen 60 50 12.37 14.65
South Gate 60 50 12.39 14.65
South Greeley 70 5,300 12.39 14.65
South Roggen 35 50 12.37 14.65
West Greeley 175 22,000 12.39 14.65
West Hudson 80 4001 2.27 14.65 <PAGE>
West La Salle 35 90 12.40 14.65
Plus Miscellaneous Mainline Taps <PAGE>
EXHIBIT 10.6(b)
TRANSPORTATION STORAGE SERVICE AGREEMENT
UNDER RATE SCHEDULE TSS
THIS AGREEMENT is made and entered into this 1st day of
October, 1993 by and between WILLIAMS NATURAL GAS COMPANY, a
Delaware corporation, having its principal office in Tulsa,
Oklahoma, hereinafter referred to as "WNG," and GREELEY GAS
COMPANY, a Delaware corporation, having its principal office in
Denver, Colorado, hereinafter referred to as "Shipper."
IN CONSIDERATION of the premises and of the mutual covenants
and agreements herein contained, WNG and Shipper agree as
follows:
ARTICLE I
QUANTITY
1.1 Subject to the provisions of this Agreement and of WNG's
Rate Schedule TSS, WNG agrees to receive such quantities of
natural gas as Shipper may cause to be tendered to WNG at the
Primary Receipt Point(s) designated on Exhibit A which are
selected from WNG's Master Receipt Point List, as revised from
time to time, for transportation and storage on a firm basis;
provided, however, that in no event shall WNG be obligated to
receive on any day in excess of the Maximum Daily Quantity (MDQ)
for each Primary Receipt Point or of the Maximum Daily
Transportation Quantity (MDTQ) for all Primary Receipt Points
within any area, all as set forth on Exhibit A.
1.2 WNG agrees to deliver and Shipper agrees to accept (or
cause to be accepted) at the Primary Delivery Point(s) taken from
the Master Delivery Point List and designated on Exhibit B a
quantity of natural gas thermally equivalent to the quantity
received by WNG for transportation and withdrawn from storage as
provided in Article 1.3 hereunder less appropriate reductions for
fuel and loss as provided in WNG's Rate Schedule TSS; provided,
however, that WNG shall not be obligated to deliver on any day
quantities in excess of the MDQ for each Primary Delivery Point
or in excess of the MDTQ within any area for all Primary Delivery
Points, all as set forth on Exhibit B.
1.3 Subject to the provisions of this Agreement and of WNG's
Rate Schedule TSS, WNG agrees to (a) inject and store such
quantities of natural gas up to the Maximum Storage Quantity
(MSQ) and the Maximum Daily Injection Quantity (MDIQ) as Shipper
may cause to be tendered to WNG for injection into storage, less
appropriate reductions for fuel and loss, and (b) withdraw such
quantities of natural gas up to Shipper's gas in storage and the
Maximum Daily Withdrawal Quantity (MDWQ) reflected on Exhibit C,
all on a firm basis.<PAGE>
ARTICLE II
DELIVERY POINT(S) AND DELIVERY PRESSURE
2.1 Natural gas to be delivered hereunder by WNG to or on
behalf of Shipper shall be delivered at the outlet side of the
measuring station(s) at or near the Delivery Point(s) designated
on Exhibit B at WNG's line pressure existing at such Delivery
Point(s).
ARTICLE III
RATE, RATE SCHEDULE AND GENERAL TERMS AND CONDITIONS
3.1 Shipper shall pay WNG each month for all service rendered
hereunder the then-effective, applicable rates and charges under
WNG's Rate Schedule TSS, as such rates and charges and Rate
Schedule TSS may hereafter be modified, supplemented, superseded
or replaced generally or as to the service hereunder. Shipper
agrees that WNG shall have the unilateral right from time to time
to file with the appropriate regulatory authority and make
effective changes in (a) the rates and charges applicable to
service hereunder, (b) the rate schedule(s) pursuant to which
service hereunder is rendered, or (c) any provision of the
General Terms and Conditions incorporated by reference in such
rate schedule(s); provided, however, Shipper shall have the right
to protest any such changes.
3.2 This Agreement in all respects is subject to the
provisions of Rate Schedule TSS, or superseding rate schedule(s),
and applicable provisions of the General Terms and Conditions
included by reference in said Rate Schedule TSS, all of which are
by reference made a part hereof.
ARTICLE IV
TERM
4.1 This Agreement shall become effective on the date of
execution and shall continue in full force and effect for an
original term until 7:00 a.m., local time on October 1, 2013;
provided, however, this Agreement shall be considered as renewed
and extended beyond such original term for successive five (5)
year terms thereafter, unless canceled, effective at the end of
the primary term or at the end of any subsequent five (5) year
term, by six (6) months advance written notice by either party.
4.2 This Agreement may be suspended or terminated by WNG in
the event Shipper fails to pay all of the amount of any bill
rendered by WNG hereunder when that amount is due; provided,
however, WNG shall give Shipper and the FERC thirty (30) days
notice prior to any suspension or termination of service.
Service may continue hereunder if within the thirty-day notice
period satisfactory assurance of payment is made by Shipper in
accord with Article 18 of the General Terms and Conditions.
Suspension or termination of this Agreement shall not excuse
2<PAGE>
Shipper's obligation to pay all demand and other charges for the
original term of the Agreement.
ARTICLE V
NOTICES
5.1 Unless otherwise agreed to in writing by the parties, any
notice, request, demand, statement or bill respecting this
Agreement shall be in writing and shall be deemed given when
placed in the regular mail or certified mail, postage prepaid and
addressed to the other party, or sent by overnight delivery
service, or by facsimile, at the following addresses or facsimile
numbers, respectively:
To Shipper:
Billing:
GREELEY GAS COMPANY
1301 Pennsylvania St., #800
Denver, CO 80203
Attn: Director, Gas Supply
Phone: 303/861-8080
Fax: 303/837-9549
Notices:
GREELEY GAS COMPANY
1301 Pennsylvania St., #800
Denver, CO 80203
Attn: Director, Gas Supply
Phone: 303/861-8080
Fax: 303/837-9549
To WNG:
Payments:
Williams Natural Gas Company
P.O. Box 3288
Tulsa, OK 74101
Attention: Revenue Accounting
All Notices:
Williams Natural Gas Company
P.O. Box 3288
Tulsa, OK 74101
Attention: Manager - Transportation Services
Fax: 918/588-3108
ARTICLE VI
3<PAGE>
MISCELLANEOUS
6.1 The interpretation, performance and enforcement of this
Agreement shall be construed in accordance with the laws of the
State of Oklahoma.
6.2 As of the date of execution of Exhibits A, B, and C
attached to this Agreement, such executed exhibits shall be
incorporated by reference as part of this Agreement. The parties
may amend Exhibits A, B, and C by mutual agreement, which
amendment shall be reflected in a revised Exhibit A, B, and C and
shall be incorporated by reference as part of this Agreement.
6.3 Any Service Agreements under Rate Schedule TSS shall not
cover service under both TSS-P and TSS-M.
6.4 OTHER THAN AS MAY BE SET FORTH HEREIN, WNG MAKES NO OTHER
WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WITHOUT LIMITATION
WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR
MERCHANTABILITY.
6.5 Other Miscellaneous
IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the day and year first above written.
ATTEST: WILLIAMS NATURAL GAS COMPANY
By: By: /s/ James O. Henderson
------------------------- --------------------------
Assistant Secretary
Title: Director, Transportation Services
---------------------------------
ATTEST/WITNESS: GREELEY GAS COMPANY
By: /s/ Richard W. Remley By: /s/ Gary L. Schlessman
---------------------------- --------------------------
Title: Assistant Secretary Title: President
------------------------- -----------------------
As Shipper
4<PAGE>
EXHIBIT A - MARKET
TO
TRANS-STORAGE REQUEST TR-0005
DATED OCTOBER 1, 1993
BETWEEN WILLIAMS NATURAL GAS COMPANY
AND GREELEY GAS COMPANY
______________________________________________________________________________
MAX
RECEIPT LOCATION(S) POINT DPY RATE TYP SEC-TWN- COUNTY ST DAILY
NUMBER AREA RNG QTY
______________________________________________________________________________
1 WNG-PRD/MKT POOL 999000 909 M MPT 5,619
2 WNG-MKT STORAGE 999021 909 M STW 8,254
POOL WITHDRAWAL
3 WNG-MASTER RECEIPT POINT
LIST IN EFFECT
______________________________________________________________________________
TOTAL MAXIMUM DAILY QUANTITY: 13,873
DTH
EFFECTIVE DATE OF THIS EXHIBIT A: October 1, 1993
GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY
BY: /s/ W. H. Warburton BY: /s/ James O. Henderson
------------------------ ------------------------
EXHIBIT A - PRODUCTION
TO
TRANS-STORAGE REQUEST TR-0005
SERVICE AGREEMENT
DATED OCTOBER 1, 1993
BETWEEN WILLIAMS NATURAL GAS COMPANY
AND GREELEY GAS COMPANY
_______________________________________________________________________________
MAX
RECEIPT LOCATION(S) POINT DPY RATE TYP SEC-TWN-RNG COUNTY ST DAILY
NUMBER AREA QTY
_______________________________________________________________________________
1 CIG-CIG-RINER 13031 492 P TER 34-21N-090W SWEETWATER WY 1,496
2 WNG-G/T OK 999400 377 P INT 4,279
HUGOTON INTERFACE
3 WNG-MASTER RECEIPT
POINT LIST IN EFFECT
_______________________________________________________________________________
TOTAL MAXIMUM DAILY QUANTITY: 5,775
DTH
EFFECTIVE DATE OF THIS EXHIBIT A: October 1, 1993
GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY
BY: /s/ W. H. Warburton BY: /s/ James O. Henderson
------------------------ ----------------------
EXHIBIT B - MARKET
TO
TRANS-STORAGE REQUEST TR-0005
SERVICE AGREEMENT
DATED OCTOBER 1, 1993
BETWEEN WILLIAMS NATURAL GAS COMPANY
AND GREELEY GAS COMPANY
________________________________________________________________________________
MAXIMUM
DELIVERY LOCATION(S) POINT DPY RATE TYP ST DAILY
NUMBER AREA QTY
________________________________________________________________________________
1 GREELEY - JOHNSON CO. 104 190 M DCL KS 500
2 GREELEY - BOURBON COUNTY 48015 095 M DCL KS 2,743
3 GREELEY - BONNER SPRGS ETC 77308 113 M DCL KS 8,070
4 GREELEY - EUREKA, TORONTO AND NEAL 77512 300 M DCL KS 2,560
5 WNG-MASTER DELIVERY POINT LIST IN EFFECT
________________________________________________________________________________
TOTAL MAXIMUM DAILY QUANTITY: 13,873 DTH
EFFECTIVE DATE OF THIS EXHIBIT B: October 1, 1993
GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY
BY: /s/ W. H. Warburton BY: /s/ James O. Henderson
------------------------- --------------------------
EXHIBIT B - PRODUCTION
TO
TRANS-STORAGE REQUEST TR-0005
SERVICE AGREEMENT
DATED OCTOBER 1, 1993
BETWEEN WILLIAMS NATURAL GAS COMPANY
AND GREELEY GAS COMPANY
_____________________________________________________________________________
MAXIMUM
DELIVERY LOCATION(S) POINT DPY RATE TYP ST DAILY
NUMBER AREA QTY
_____________________________________________________________________________
1 PRD/MKT POOL DELIVERY 999000 909 P PPT KS 5,775
2 WKG- MASTER DELIVERY POINT LIST IN EFFECT
______________________________________________________________________________
TOTAL MAXIMUM DAILY QUANTITY: 5,775 DTH
EFFECTIVE DATE OF THIS EXHIBIT B: October 1, 1993
GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY
BY: /s/ W. H. Warburton BY: /s/ James O. Henderson
--------------------------- -------------------------
9<PAGE>
EXHIBIT C - STORAGE
TO
TRANS-STORAGE REQUEST TR-0005
SERVICE AGREEMENT
DATED OCTOBER 1, 1993
BETWEEN WILLIAMS NATURAL GAS COMPANY
AND GREELEY GAS COMPANY
________________________________________________________________________
MAXIMUM DAILY WITHDRAWAL QUANTITY: 8,254 DTH
MAXIMUM STORAGE QUANTITY:** 272,382 DTH
**MAXIMUM DAILY WITHDRAWAL QUANTITY TIMES 33
EFFECTIVE DATE OF THIS EXHIBIT C: October 1, 1993
GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY
BY: /s/ W. H. Warburton BY: /s/ James O. Henderson
-------------------------- --------------------------
11<PAGE>
EXHIBIT 10.6(c)
Contract No. 31013
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE NNT-1
between
COLORADO INTERSTATE GAS COMPANY
and
GREELEY GAS COMPANY
DATED: October 1, 1993, or the date in which CIG commences
service pursuant to its Compliance Tariff filed in Docket
No. RS92-4-000, et al., whichever is later.<PAGE>
TABLE OF CONTENTS
Article Page No.
I QUANTITIES OF GAS TO BE TRANSPORTED AND STORED . . . 1
II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY . . . . 2
III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 3
IV TERM . . . . . . . . . . . . . . . . . . . . . . . . 4
V CANCELLATION OF PRIOR CONTRACTS . . . . . . . . . . 4
VI OTHER OPERATING PROVISIONS . . . . . . . . . . . . . 4
VII MODIFICATIONS . . . . . . . . . . . . . . . . . . . 6
VIII NOTICES . . . . . . . . . . . . . . . . . . . . . . 6
EXHIBIT "A"
EXHIBIT "B"
- 2 -<PAGE>
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE NNT-1
THIS AGREEMENT is made and entered into as of this 1st Day of
October, 1993, or the date in which CIG commences service
pursuant to its Compliance Tariff filed in Docket No. RS92-4-000,
et al., whichever is later, by and between COLORADO INTERSTATE
GAS COMPANY, hereinafter called "Transporter," and GREELEY GAS
COMPANY, hereinafter called "Shipper".
In consideration of the mutual promises hereinafter contained,
Shipper and Transporter agree as follows:
ARTICLE I
QUANTITIES OF GAS TO BE TRANSPORTED AND STORED
1.1 Maximum Delivery Quantity ("MDQ"). Shipper's MDQ is
16,005 Dth per Day during the Winter Season and 4,896 Dth per Day
during the Summer Season.
1.2 Transportation Service. Transportation Service between
and at Primary Point(s) of Receipt and Primary Point(s) of
Delivery shall be on a firm basis. Service at and involving
Secondary Point(s) of Receipt and Delivery shall be scheduled
subject to capacity availability following all firm Transpor-
tation Service between Primary Point(s) of Receipt and Delivery
and ahead of any interruptible Transportation Service at such
point(s).
1.3 Maximum Daily Transportation Quantity ("MDTQ").
Shipper's MDTQ is 4,896 Dth per Day.
1.4 Maximum Available Capacity ("MAC"). Shipper's MAC is
422,142 Dth.<PAGE>
1.5 Maximum Daily Injection Quantity ("MDIQ"). Shipper's
MDIQ is 1/150th of Shipper's MAC or 2,814 Dth per Day.
1.6 Maximum Daily Withdrawal Quantity ("MDWQ"). Shipper's
MDWQ is 1/38th of Shipper's MAC or 11,109 Dth per Day. MDWQ is
subject to adjustment as actual gas in place declines over the
Withdrawal Period as explained in Article 1 of the General Terms
and Conditions of Transporter's FERC Gas Tariff.
1.7 Authorized Overrun Quantities. On any Day upon request
by Shipper and with Transporter's consent, Shipper may Tender and
Transporter may accept for service hereunder quantities of gas in
excess of Shipper's MDQ or Shipper's Point of Receipt or Delivery
Quantities at each Point of Receipt or Delivery.
1.8 Summer Season Overrun. During the Summer Season,
Shipper may take Deliveries in excess of the quantities nominated
by Shipper at the Point(s) of Receipt up to its full Winter
Season MDQ, limited by Shipper's ADWQ and Shipper shall pay the
NNT-1 Commodity rate on the Schedule of Rates Sheets for the
Summer Season Overrun quantities delivered. Such quantities
shall be subject to the same terms and conditions as if they were
Winter Season quantities.
ARTICLE II
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
2.1 Receipt. Transporter agrees to accept Receipt
Quantities at the Point(s) of Receipt identified in the attached
Exhibit "A" which is incorporated herein by reference.
- 2 - <PAGE>
2.2 Delivery. Transporter agrees to transport and Deliver
Delivery Quantities to Shipper (or for Shipper's account) at the
Point(s) of Delivery identified in the attached Exhibit "A."
2.3 Secondary Points of Receipt and Delivery. Receipt and
Delivery of quantities by Transporter at Secondary Point(s) of
Receipt and/or Secondary Point(s) of Delivery will be scheduled
and allocated capacity pursuant to Article 5 of the General Terms
and Conditions of Transporter's FERC Gas Tariff. Shipper shall
be entitled to receive service at Secondary Point(s) of Receipt
and Delivery by nominating for service at such locations. When
nominating for service at Secondary Point(s), Shipper shall
designate the capacity being shifted from Primary Points for
service at the Secondary Points.
ARTICLE III
APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE
3.1 Rate Schedule. Each Month, Shipper shall pay
Transporter for No-Notice Transportation Service rendered
hereunder at the rates and surcharges set forth on Exhibit "B,"
which is incorporated herein by reference, for the Term of Rate
provided therein. Once the Term of Rate has expired, payment
shall be at the maximum rates and surcharges set forth on the
Schedule of Rates Sheets unless otherwise agreed.
3.2 Incorporation by Reference. This Agreement in all
respects shall be subject to Rate Schedule NNT-1 and to the
General Terms and Conditions of Transporter's FERC Gas Tariff
(Tariff) as filed with, and made effective by, the FERC (as they
- 3 - <PAGE>
may be amended pursuant to Article VII of this Agreement), all of
which are by reference made a part hereof.
3.3 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.
ARTICLE IV
TERM
4.1 Effective Date. This Agreement shall become effective
on October 1, 1993, or the date in which Transporter commences
service pursuant to its Compliance Tariff filed in Docket
No. RS92-4-000, et al., whichever is later.
4.2 Termination Date. This Agreement shall continue in
full force and effect for a term extending through September 30,
1996.
4.3 Termination Obligations. Termination of this Agreement
shall not relieve Transporter and Shipper of the obligation to
correct any imbalances, or relieve Shipper of the obligation to
pay money due to Transporter. All warranties and indemnities
shall survive the termination of this Agreement.
ARTICLE V
CANCELLATION OF PRIOR CONTRACTS
5.1 Cancellation of Prior Contracts. When this Agreement
becomes effective, it shall supersede and cancel the following
contract(s) between the Parties: The Gas Sales Agreement between
- 4 - <PAGE>
Transporter and Shipper dated February 1, 1993, and any
amendments thereto and referred to as Transporter's Agreement
No. R-4-AP.
ARTICLE VI
OTHER OPERATING PROVISIONS
6.1 Shippers under this Rate Schedule NNT-1 shall be
subject to the Joint Monthly Operating Plan, Operational Flow
Orders, and Configuration Flow Orders as provided in Article 7 of
the General Terms and Conditions of the Tariff.
6.2 First of the Month Nominations. At least four Business
Days, or, for Shippers using Transporter's electronic bulletin
board, two Business Days, before the first Day of each Month,
Shipper shall provide Transporter with a schedule (in writing or
by Electronic Transmission) showing the daily quantities to be
Tendered to Transporter during the first four Days of the Month
at each Point of Receipt including the producing area (including
county and state) of the gas to be Tendered. Nominations shall
be addressed as set forth in Article VIII of this Agreement.
6.3 Daily Nominations. Unless otherwise agreed, Shipper
shall submit daily written nominations to Transporter 27 hours
prior to the beginning of the Day of Delivery (e.g., nominations
shall be made by 10:00 a.m., Central Standard Time, on Monday for
gas to be Tendered beginning at 1:00 p.m., Central Standard Time,
on Tuesday). For each Agreement, Shipper shall nominate in
writing or by Electronic Transmission the quantity which Shipper
intends to Tender at the Point(s) of Receipt and to receive at
the Point(s) of Delivery, including an allocation of Point of
- 5 - <PAGE>
Receipt Quantities to each Point of Delivery in the event of
multiple Delivery Points.
Transporter shall attempt to verify all nominations and
confirm service to Shipper no later than four hours prior to the
Day for which the nominations are to be effective.
Transporter is not responsible for assuring that the
nominated quantities are actually Tendered to Transporter at the
Point(s) of Receipt.
All service performed under this Agreement shall be
performed pursuant to 18 CFR 284.221 authority, unless Shipper
elects service to be performed pursuant to Transporter's
18 CFR 284.101 (Section 311) authority. In that event,
Transporter shall only accept, and Shipper shall only make,
nominations for service to be performed pursuant to
18 CFR 284.101 (Section 311) in accordance with the regulations
governing the provisions of such service, and after Transporter
has received an "on behalf of" letter acceptable to Transporter.
6.4 Estimates. For planning purposes, Transporter may,
from time to time, request estimates of Shipper's annual
quantity, average daily quantity, or peak Day quantity. In the
event that such a request is made, Shipper shall reply in writing
within 45 Days of the request.
6.5 Planning Information. Transporter may request other
planning information as needed from time to time and Shipper
shall comply with all reasonable requests.
- 6 -<PAGE>
ARTICLE VII
MODIFICATIONS
7.1 Modifications. Certain provisions of the General Terms
and Conditions and/or Rate Schedule NNT-1 are modified for the
purpose of this Agreement, as specified below: None.
ARTICLE VIII
NOTICES
8.1 Notices, Statements, and Bills. Any notice, statement,
or bill provided for in this Agreement shall be in writing and
shall be considered as having been given if hand carried,
telecopied or mailed by United States Mail, postage prepaid, to
the following addresses, respectively:
To Shipper:
Invoices for Transportation:
Greeley Gas Company
1301 Pennsylvania Street, Suite 800
Denver, Colorado 80203-5015
Attention: Bill Warburton
All Notices:
Greeley Gas Company
1301 Pennsylvania Street, Suite 800
Denver, Colorado 80203-5015
Attention: Bill Warburton
To Transporter:
Payments for Transportation:
Colorado Interstate Gas Company
Department 208
Denver, Colorado 80291
All Notices:
Colorado Interstate Gas Company
P. O. Box 1087
Colorado Springs Colorado 80944
Telecopy No. (719) 520-4810
Attention: Transportation & Exchange Department
- 7 -<PAGE>
All Nominations:
Colorado Interstate Gas Company
Colorado Springs, Colorado 80944
Telecopy No. (719) 520-4411
Attention: Volume Management, Transmission
8.2 Agents. Shipper must provide written notice to
Transporter of the name, and any other pertinent information, of
another person ("Agent") that has agency authority to act for
Shipper in connection with (1) the Joint Monthly Operating Plan
as discussed in Article 7 of the General Terms and Conditions of
the Tariff, (2) operation of pipelines, facilities, and wells in
connection with this Agreement, (3) Operational Flow Orders or
Configuration Flow Orders as discussed in Article 7 of the
General Terms and Conditions of the Tariff, and/or (4) other
matters covered by this Agreement. If the Agent has the
authority in (2) and (3), above, operating notices shall be
served upon the Agent alone. The Shipper remains bound by its
obligations under the Tariff, and commitments made by the Agent
on behalf of the Shipper are binding on the Shipper as if made by
the Shipper. The Shipper must provide prompt written notice of
the termination of the agency.
- 8 - <PAGE>
IN WITNESS WHEREOF, the Parties hereto have executed this
Agreement.
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By /s/ S. W. ZUCKWEILER
-----------------------------
S. W. Zuckweiler
Vice President
GREELEY GAS COMPANY
(Shipper)
Attest: By /s/ Richard W. Remley
-----------------------------
Richard W. Remley
-----------------------------
By: /s/ W. J. Warburton (Print or type name)
-------------------
Title: Director Gas Supply Senior Vice President
------------------- -----------------------------
(Print or type title)
- 9 -<PAGE>
Page 1 of 3
EXHIBIT "A"
to
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
DATED: October 1, 1993, or the date in which CIG commences
service pursuant to its Compliance Tariff filed in Docket No.
RS92-4-000, et al., whichever is later.
1. Shipper's Maximum Delivery Quantity: MDQ: 4,896 Dth per
Day during the Summer Season and is 16,005 Dth per Day
during the Winter Season (Note 4).
2. Shipper's Maximum Daily Transportation Quantity: MDTQ:
4,896 Dth per Day.
3. Shipper's Maximum Available Capacity: MAC: 422,142 Dth.
4. Shipper's Maximum Daily Injection Quantity: MDIQ:
2,814 Dth.
5. Shipper's Maximum Daily Withdrawal Quantity: MDWQ:
11,109 Dth.
(1/38th of MAC)
Point of Maximum
Receipt Quantity Receipt
Primary Point(s) of Receipt (Dth per Day) Pressure
(Note 1) (Note 2) p.s.i.g.
---------------------------- ---------------- --------
Northern System
Uinta 593 720
Echo Springs Master Meter 300 850
Lost Cabin 1,200 1,100
Central System
Lakin Master Meter 839 900
As may be mutually agreed
by the Parties 30 <PAGE>
Page 2 of 3
EXHIBIT "A"
Point of Maximum
Delivery Quantity Delivery
Primary Point(s) of Delivery (Dth per Day) Pressure
(Note 1) (Note 3) p.s.i.g.
---------------------------- ----------------- --------
Southern System
Bivins Master Meter 674 479
Mocane-Warren Plant 460 800
Greenwood Master Meter 800 761
Canon City 11,855 (Note 5) (Note 6)
Colorado State Penitentiary 591 (Note 5) 100
Florence City Gate 2,265 (Note 5) 60
Penrose City Gate 394 (Note 5) 60
Penrose South 74 (Note 5) Line
Pressure
Portland City Gate 3,073 (Note 5) 100
Pritchett City Gate 295 (Note 5) 150
Fremont County Industrial Park 148 (Note 5) Line
Pressure
The Piggery 15 (Note 5) Line
Pressure
Engineer's Station 476+78 15 (Note 5) Line
Pressure
Penrose PBS-2 295 (Note 5) Line
Pressure
Eads City Gate 884 (Note 5) 60
Brandon Station 832 (Note 5) 350
L. J. Stafford 156 (Note 5) Line
Pressure
Springfield 3,120 (Note 5) Line
Pressure
NOTES: (1) Information regarding Points of Receipt and Points
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.<PAGE>
Page 3 of 3
EXHIBIT "A"
(2) Point of Receipt Quantities may be increased by an
amount equal to Transporter's effective fuel
reimbursement.
(3) The sum of the Primary Point of Delivery Quantities
shall be equal to or less than Shipper's MDQ.
(4) In Docket No. RP93-99, CIG's conversion to a thermal
tariff is subject to review as to methodology,
factors, or any other issue involved in the
transition from a volumetric basis to a thermal
basis. Should such review result in a change in the
basis upon which the thermal quantities used in this
service agreement were determined, such thermal
quantities shall be adjusted as required.
(5) Transporter's obligation to make deliveries at this
Primary Point of Delivery shall be limited to the
amount shown or the meter capacity, whichever is
less. Further, Transporter's obligation to make
deliveries at these Primary Points of Delivery under
this Agreement and under all Firm Service Agreements
shall be limited in the aggregate to the amount
shown or to the meter capacity whichever is less.
(6) Line pressure but not less than 100 p.s.i.g.<PAGE>
Page 1 of 2
EXHIBIT "B"
to
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
DATED: October 1, 1993, or the date in which CIG commences
service pursuant to its Compliance Tariff filed in Docket No.
RS92-4-000, et al., whichever is later.
<TABLE>
<CAPTION>
R1 Res- Commod- Fuel
ervation ity Reimburse- Sur-
Point of Receipt Point of Delivery Rate Rate Term of Rate ment charges
- ---------------- ----------------- -------- ------- ------------ ---------- -------
<S> <C> <C> <C> <C> <C> <C>
All Primary and All Primary and (Note 1) (Note 1) Through (Note 2) (Note 3)
Secondary Points Secondary Points 9/30/96
</TABLE>
NOTES: (1) The rates for service hereunder shall be
Transporter's maximum rates for service under Rate
Schedule NNT-1 or other superseding Rate Schedule,
as such rates may be changed from time to time.
(2) Fuel usage and lost and unaccounted-for deductions
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. <PAGE>
Page 2 of 2
EXHIBIT "B"
NOTES: (3) Applicable Surcharges:
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.
Gas Quality Control:
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,
both as set forth in the Tariff.
Gas Supply Transition:
The Gas Supply Transition Surcharge shall be
assessed pursuant to Article 21 of the General
Terms and Conditions as set forth in the Tariff.
ACA:
Transporter's applicable ACA Surcharge shall be
added to all discounted rates except that in no
event shall the discounted rate plus the ACA
Surcharge exceed Transporter's maximum rate as
stated in the Schedule of Rates in the Tariff.<PAGE>
Contract No. 31013000A
AMENDMENT
DATED: January 1, 1994
to
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE NNT-1
DATED: October 1, 1993
between
COLORADO INTERSTATE GAS COMPANY
and
GREELEY GAS COMPANY<PAGE>
AMENDMENT TO
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE NNT-1
THIS AGREEMENT, made and entered into this 1st Day of
January, 1994, by and between COLORADO INTERSTATE GAS COMPANY,
hereinafter referred to as "Transporter," and GREELEY GAS
COMPANY, hereinafter referred to as "Shipper."
WHEREAS, Transporter and Shipper entered into a
Transportation Service Agreement ("Agreement") dated October 1,
1993, providing for the transportation by Transporter for Shipper
pursuant to 18 CFR 284.221 authority and/or 18 CFR 284.101 (see
Section 6.3 as applicable); and
WHEREAS, Transporter and Shipper desire to amend the
Agreement effective January 1, 1994, to revise the Primary Points
of Delivery as stated in Exhibit "A" to the Agreement;
NOW, THEREFORE, in consideration of the premises and the
mutual covenants hereinafter contained, Transporter and Shipper
agree to amend the Agreement as follows:
Effective January 1, 1994, Exhibit "A" shall be deleted in
its entirety and the attached Exhibit "A" shall be substituted
therefor.
This Amendment shall be effective as of January 1, 1994,
and except as herein amended, the Agreement shall in all respects
remain in full force and effect. <PAGE>
IN WITNESS WHEREOF, the Parties have executed this
Amendment.
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By /s/ Donald J. Zinko
-----------------------------
Donald J. Zinko
Senior Vice President
GREELEY GAS COMPANY
(Shipper)
ATTEST:
By /s/ Gary L. Schlessman
-----------------------------
By Gary L. Schlessman
-------------------------- -----------------------------
Title: (Print or type name)
President
-----------------------------
(Print or type title)
- 2 -<PAGE>
Page 1 of 3
EXHIBIT "A"
to
NO-NOTICE TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
Agreement Dated: October 1, 1993
Amendment Dated: January 1, 1994
1. Shipper's Maximum Delivery Quantity: MDQ: 4,896 Dth per
Day during the Summer Season and is 16,005 Dth per Day
during the Winter Season (Note 4).
2. Shipper's Maximum Daily Transportation Quantity: MDTQ:
4,896 Dth per Day.
3. Shipper's Maximum Available Capacity: MAC: 422,142 Dth.
4. Shipper's Maximum Daily Injection Quantity: MDIQ:
2,814 Dth.
5. Shipper's Maximum Daily Withdrawal Quantity: MDWQ:
11,109 Dth.
(1/38th of MAC)
Point of Maximum
Receipt Quantity Receipt
Primary Point(s) of Receipt (Dth per Day) Pressure
(Note 1) (Note 2) p.s.i.g.
--------------------------- ---------------- --------
Northern System
Uinta 593 720
Echo Springs Master Meter 300 850
Lost Cabin 1,200 1,100
Central System
Lakin Master Meter 839 900
As may be mutually agreed
by the Parties 30 <PAGE>
Page 2 of 3
EXHIBIT "A"
Point of Maximum
Delivery Quantity Delivery
Primary Point(s) of Delivery (Dth per Day) Pressure
(Note 1) (Note 3) p.s.i.g.
Southern System
Bivins Master Meter 674 479
Mocane-Warren Plant 460 800
Greenwood Master Meter 800 761
Canon City Group (Note 5):
Canon City 11,855 (Note 6) (Note 7)
Colorado State Penitentiary 591 (Note 6) 100
Florence City Gate 2,265 (Note 6) 60
Penrose City Gate 394 (Note 6) 60
Penrose South 74 (Note 6) Line Pressure
Portland City Gate 3,073 (Note 6) 100
Pritchett City Gate 295 (Note 6) 150
Fremont County Industrial Park 148 (Note 6) Line Pressure
The Piggery 15 (Note 6) Line Pressure
Engineer's Station 476+78 15 (Note 6) Line Pressure
Penrose PBS-2 295 (Note 6) Line Pressure
Eads Group (Note 8):
Eads City Gate 884 (Note 6) 60
Brandon Station 832 (Note 6) 350
L. J. Stafford 156 (Note 6) Line Pressure
Springfield 1,081 (Note 6) Line Pressure
McClave Delivery 1,000 (Note 6)
500
NOTES: (1) Information regarding Points of Receipt and Points
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) Point of Receipt Quantities may be increased by an
amount equal to Transporter's effective fuel
reimbursement.
(3) The sum of the Primary Point of Delivery Quantities
shall be equal to or less than Shipper's MDQ.<PAGE>
Page 3 of 3
EXHIBIT "A"
(4) In Docket No. RP93-99, CIG's conversion to a thermal
tariff is subject to review as to methodology,
factors, or any other issue involved in the
transition from a volumetric basis to a thermal
basis. Should such review result in a change in the
basis upon which the thermal quantities used in this
service agreement were determined, such thermal
quantities shall be adjusted as required.
(5) Transporter's obligation to make deliveries at all
Primary Points of Delivery included in the Canon
City Group shall be limited in the aggregate to
12,644 Dth per Day under this Agreement.
(6) Transporter's obligation to make deliveries at this
Primary Point of Delivery shall be limited to the
amount shown or the meter capacity, whichever is
less. Further, Transporter's obligation to make
deliveries at these Primary Points of Delivery under
this Agreement and under all Firm Service Agreements
shall be limited in the aggregate to the amount
shown or to the meter capacity whichever is less.
(7) Line pressure but not less than 100 p.s.i.g.
(8) Transporter's obligation to make deliveries at all
Primary Points of Delivery included in the Eads
Group shall be limited in the aggregate to 1,280 Dth
per Day under this Agreement.<PAGE>
EXHIBIT 10.6(d)
Contract No. 35009
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-2
between
COLORADO INTERSTATE GAS COMPANY
and
GREELEY GAS COMPANY
DATED: October 1, 1993, or the date in which CIG commences
service pursuant to its Compliance Tariff filed in Docket
No. RS92-4-000, et al., whichever is later.<PAGE>
TABLE OF CONTENTS
Article Page No.
I QUANTITIES OF GAS TO BE TRANSPORTED . . . . . . . . . 1
II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY . . . . 2
III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 2
IV TERM . . . . . . . . . . . . . . . . . . . . . . . . 3
V CANCELLATION OF PRIOR CONTRACTS . . . . . . . . . . . 3
VI OTHER OPERATING PROVISIONS . . . . . . . . . . . . . 4
VII MODIFICATIONS . . . . . . . . . . . . . . . . . . . . 5
VIII NOTICES . . . . . . . . . . . . . . . . . . . . . . . 5
EXHIBIT "A"
EXHIBIT "B"
2<PAGE>
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-2
THIS AGREEMENT is made and entered into as of this 1st Day
of October, 1993, or the date in which CIG commences service
pursuant to its Compliance Tariff filed in Docket No. RS92-4-000,
et al., whichever is later, by and between COLORADO INTERSTATE
GAS COMPANY, hereinafter called "Transporter," and GREELEY GAS
COMPANY, hereinafter called "Shipper."
In consideration of the mutual promises hereinafter
contained, Shipper and Transporter agree as follows:
ARTICLE I
QUANTITIES OF GAS TO BE TRANSPORTED
1.1 Maximum Delivery Quantity. Shipper's Maximum Delivery
Quantity is 1,408 Dth per Day.
1.2 Transportation Service. Transportation Service at and
between Primary Point(s) of Receipt and Primary Point(s) of
Delivery shall be on a firm basis. Service involving and at
Secondary Point(s) of Receipt and Delivery shall be scheduled,
subject to capacity availability, following all firm
transportation services between Primary Point(s) of Receipt and
Delivery and ahead of any interruptible Transportation Service at
such point(s).
1.3 Authorized Overrun Quantity. On any Day upon request
of Shipper and with Transporter's consent, Shipper may Tender and
Transporter may accept for transportation quantities of gas in
excess of Shipper's Maximum Delivery Quantity or Shipper's Point
of Receipt or Delivery Quantities at each Point of Receipt or
Delivery.<PAGE>
ARTICLE II
POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY
2.1 Receipt. Transporter agrees to accept Receipt
Quantities at the Primary Point(s) of Receipt identified in
Exhibit "A," which is incorporated herein by reference.
2.2 Delivery. Transporter agrees to transport and Deliver
Delivery Quantities to Shipper (or for Shipper's account) at the
Primary Point(s) of Delivery identified in Exhibit "A."
2.3 Secondary Point(s) of Receipt and Delivery. Receipt
and Delivery of quantities at Secondary Point(s) of Receipt
and/or Secondary Point(s) of Delivery will be scheduled and
allocated capacity pursuant to Article 5 of the General Terms and
Conditions of this Tariff. Shipper shall be entitled to receive
service at Secondary Point(s) of Receipt and Delivery by
nominating for service at such locations. When nominating for
service at Secondary Point(s), Shipper shall designate the
capacity being shifted from Primary Point(s) for service at the
Secondary Point(s).
ARTICLE III
APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE
3.1 Rate Schedule. Each Month, Shipper shall pay
Transporter for Transportation Service provided hereunder at the
rates and surcharges set forth on Exhibit "B," which is
incorporated herein by reference, for the Term of Rate provided
therein. Once the Term of Rate has expired, payment shall be at
the maximum rates and surcharges set forth on the Schedule of
Rates Sheets unless otherwise agreed.
2 <PAGE>
3.2 Incorporation by Reference. This Agreement in all
respects shall be subject to Rate Schedule TF-2 and the General
Terms and Conditions of Transporter's FERC Gas Tariff (Tariff)
filed with, and made effective by, the FERC (as they may be
amended pursuant to Article VII of this Agreement), all of which
are by reference made a part hereof.
3.3 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.
ARTICLE IV
TERM
4.1 Effective Date. This Agreement shall become effective
on October 1, 1993, or the date in which CIG commences service
pursuant to its Compliance Tariff filed in Docket No. RS92-4-000,
et al., whichever is later.
4.2 Termination Date. This Agreement shall continue in
full force and effect for a term extending through September 30,
1996.
4.3 Termination Obligations. Termination of this
Agreement shall not relieve Transporter and Shipper of the
obligation to correct any quantity imbalances, or relieve Shipper
of the obligation to pay money due to Transporter. All
warranties and indemnities shall survive the termination of this
Agreement.
3<PAGE>
ARTICLE V
CANCELLATION OF PRIOR CONTRACTS
5.1 Cancellation of Prior Contracts. When this Agreement
becomes effective, it shall only supersede and cancel the
following contract(s) between the Parties: None.
ARTICLE VI
OTHER OPERATING PROVISIONS
6.1 Shippers under this Rate Schedule TF-2 shall be
subject to the Joint Monthly Operating Plan, Operational Flow
Orders, and Configuration Flow Orders as provided in Article 7 of
the General Terms and Conditions of the Tariff.
6.2 First of the Month Nominations. At least four
Business Days, or, for Shippers using Transporter's electronic
bulletin board, two Business Days, before the first Day of each
Month, Shipper shall provide Transporter with a schedule (in
writing or by Electronic Transmission) showing the daily
quantities to be Tendered to Transporter during the first four
Days of the Month at each Point of Receipt including the
producing area (including county and state) of the gas to be
Tendered and an allocation of such quantity at each Point of
Delivery. Nominations shall be addressed as set forth in
Article VIII of this Agreement.
6.3 Daily Nominations. Unless otherwise agreed, Shipper
shall submit daily written nominations to Transporter 27 hours
prior to the beginning of the Day of Delivery (e.g., nominations
shall be made by 10:00 a.m., Central Standard Time, on Monday for
gas to be Tendered beginning at 1:00 p.m., Central Standard Time,
on Tuesday). For each Agreement, Shipper shall nominate in
4 <PAGE>
writing or by Electronic Transmission the quantity which Shipper
intends to Tender at the Point(s) of Receipt and to receive at
the Point(s) of Delivery, including an allocation of Point of
Receipt Quantities to each Point of Delivery in the event of
multiple Delivery Points.
Transporter shall attempt to verify all nominations
and confirm service to Shipper no later than four hours prior to
the Day for which the nominations are to be effective.
Transporter is not responsible for assuring that the
nominated quantities are actually Tendered to Transporter at the
Point(s) of Receipt.
All service performed under this Agreement shall be
performed pursuant to 18 CFR 284.221 authority, unless Shipper
elects service to be performed pursuant to Transporter's
18 CFR 284.101 (Section 311) authority. In that event,
Transporter shall only accept, and Shipper shall only make,
nominations for service to be performed pursuant to
18 CFR 284.101 (Section 311) in accordance with the regulations
governing the provisions of such service, and after Transporter
has received an "on behalf of" letter acceptable to Transporter.
6.4 Estimates. For planning purposes, Transporter may,
from time to time, request estimates of Shipper's annual
quantity, average daily quantity, or peak Day quantity. In the
event that such a request is made, Shipper shall reply in writing
within 45 Days of the request.
6.5 Planning Information. Transporter may request other
planning information as needed from time to time and Shipper
shall comply with all reasonable requests.
5 <PAGE>
ARTICLE VII
MODIFICATIONS
7.1 Modifications. Certain provisions of the General
Terms and Conditions and/or Rate Schedule TF-2 are to be modified
for the purpose of this Agreement, as specified below: None.
ARTICLE VIII
NOTICES
8.1 Notices, Statements, and Bills. Any notice,
statement, or bill provided for in this Agreement shall be in
writing and shall be considered as having been given if hand
carried, telecopied, or mailed by United States mail, postage
prepaid, to the following addresses, respectively:
To Shipper:
Invoices for Transportation:
Greeley Gas Company
1301 Pennsylvania Street, Suite 800
Denver, Colorado 80203-5015
Attention: Bill Warburton
All Notices:
Greeley Gas Company
1301 Pennsylvania Street, Suite 800
Denver, Colorado 80203-5015
Attention: Bill Warburton
To Transporter:
Payments for Transportation:
Colorado Interstate Gas Company
Department 208
Denver, Colorado 80291
All Notices:
Colorado Interstate Gas Company
P. O. Box 1087
Colorado Springs, Colorado 80944
Telecopy No. (719) 520-4810
Attention: Transportation & Exchange
Department
6<PAGE>
All Nominations:
Colorado Interstate Gas Company
Colorado Springs, Colorado 80944
Telecopy No. (719) 520-4411
Attention: Volume Management, Transmission
8.2 Agents. Shipper must provide written notice to
Transporter of the name, and any other pertinent information, of
another person ("Agent") that has agency authority to act for
Shipper in connection with (1) the Joint Monthly Operating Plan
as discussed in Article 7 of the General Terms and Conditions of
the Tariff, (2) operation of pipelines, facilities, and wells in
connection with this Agreement, (3) Operational Flow Orders and
Configuration Flow Orders as discussed in Article 7 of the
General Terms and Conditions of the Tariff, and/or (4) other
matters covered by this Agreement. If the Agent has the
authority in (2) and (3), above, operating notices shall be
served upon the Agent alone. The Shipper remains bound by its
obligations under the Tariff, and commitments made by the Agent
on behalf of the Shipper are binding on the Shipper as if made by
the Shipper. The Shipper must provide prompt written notice of
the termination of the agency.
IN WITNESS WHEREOF, the Parties have executed this
Agreement.
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By /s/ S. W. Zuckweiler
-----------------------------
S. W. Zuckweiler
Vice President
7<PAGE>
GREELEY GAS COMPANY
(Shipper)
Attest:
By /s/Richard W. Remley
-----------------------------
By /s/ W. F. Warburton Richard W. Remley
-------------------------- -----------------------------
Title: (Print or type name)
Director Gas Supply Senior Vice President
-----------------------------
(Print or type title)
8<PAGE>
Page 1 of 3
EXHIBIT "A"
to
FIRM TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
DATED: October 1, 1993, or the date in which CIG commences
service pursuant to its Compliance Tariff filed in Docket
No. RS92-4-000, et al., whichever is later.
1. Shipper's Maximum Delivery Quantity: 1,408 Dth per Day (Note
3).
Point of Maximum
Receipt Quantity Receipt
Primary Point(s) of Receipt (Dth per Day) Pressure
(Note 1) (Note 2) p.s.i.g.
Lakin Master Meter 1,408 900
Point of Maximum
Delivery Quantity Delivery
Primary Point(s) of Delivery (Dth per Day) Pressure
(Note 1) (Note 4) p.s.i.g.
Canon City Group (Note 5)
Canon City 1,112 (Note 7) (Note 9)
Colorado State Penitentiary 591 (Note 7) 100
Florence City Gate 1,112 (Note 7) 60
Penrose City Gate 394 (Note 7) 60
Penrose South 74 (Note 7) Line Pressure
Portland City Gate 1,112 (Note 7) 100
Pritchett City Gate 295 (Note 7) 150
Fremont County Industrial Park 148 (Note 7) Line Pressure
The Piggery 15 (Note 7) Line Pressure
Engineer's Station 476+78 15 (Note 7) Line Pressure
Penrose PBS-2 295 (Note 7) Line Pressure<PAGE>
Page 2 of 3
EXHIBIT "A"
Point of Maximum
Delivery Quantity Delivery
Primary Point(s) of Delivery (Dth per Day) Pressure
(Note 1) (Note 4) p.s.i.g.
Eads Group (Note 6)
Eads City Gate 113 (Note 7) 60
Brandon Station 113 (Note 7) 350
L. J. Stafford 113 (Note 7) Line
Pressure
Springfield 183 (Note 8) Line
Pressure
NOTES: (1) Information regarding Points of Receipt and Points
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) Point of Receipt Quantities may be increased by an
amount equal to Transporter's effective fuel
reimbursement.
(3) In Docket No. RP93-99, CIG's conversion to a thermal
tariff is subject to review as to methodology,
factors, or any other issue involved in the
transition from a volumetric basis to a thermal
basis. Should such review result in a change in the
basis upon which the thermal quantities used in this
service agreement were determined, such thermal
quantities shall be adjusted as required.
(4) The sum of the Primary Point of Delivery Quantities
shall be equal to or less than Shipper's MDQ.
(5) Transporter's obligation to make deliveries at all
Primary Points of Delivery included in the Canon
City Group shall be limited in the aggregate to
1,112 Dth per Day.
(6) Transporter's obligation to make deliveries at all
Primary Points of Delivery included in the Eads
Group shall be limited in the aggregate to 113 Dth
per Day.<PAGE>
Page 3 of 3
EXHIBIT "A"
NOTES: (7) Transporter's obligation to make deliveries at this
Point of Delivery under this Agreement and all other
Firm Service Agreements shall be limited in the
aggregate to the following volumes, or the meter
capacity, whichever is less.
Canon City 11,855
Colorado State Penitentiary 591
Florence City Gate 2,265
Penrose City Gate 394
Penrose South 74
Portland City Gate 3,073
Pritchett City Gate 295
Fremont County Industrial Park 148
The Piggery 15
Engineer's Station 476+78 15
Penrose PBS-2 295
Eads City Gate 884
Brandon Station 832
L. J. Stafford 156
(8) Transporter's obligation to make deliveries to this
Point of Delivery shall be limited to 183 Dth per
Day. Further, Transporter's obligation to make
deliveries at this Point under this Agreement and
all other Firm Service Agreements shall be limited
to 3,120 or the meter capacity, whichever is less.
(9) Line pressure but not less than 100 p.s.i.g.<PAGE>
Page 1 of 2
EXHIBIT "B"
to
FIRM TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
DATED: October 1, 1993, or the date in which Transporter
commences service pursuant to its Compliance Tariff filed in
Docket No. RS92-4-000, et al., whichever is later.
Primary Primary R1 Res- Commod- Fuel Hourly
Point of Point of ervation ity Reimburse- Flex- Sur-
Receipt Delivery Rate Rate Term of Rate ment ibility charges
- -------- -------- -------- ------- ------------ ---------- ------- -------
All All (Note 1) (Note 1) Through (Note 2) (Note 1) (Note 3)
9/30/96
Secondary Secondary R1 Res- Commod- Fuel Hourly
Point of Point of ervation ity Term of Reimburse- Flex- Sur-
Receipt Delivery Rate Rate Rate ment ibility charges
- --------- --------- -------- ------- ------- ---------- ------- -------
All All (Note 1) (Note 1) Through (Note 2) (Note 1) (Note 3)
9/30/96
NOTES: (1) The rates for service hereunder shall be
Transporter's maximum rates for service under Rate
Schedules TF-2 and HFS-1, if applicable, or other
superseding Rate Schedules, as such rates may be
changed from time to time. Transporter shall apply
the HFS-1 rate to Shipper's MDQ (1,408 Dth) unless
Shipper notifies Transporter in writing that Shipper
does not elect this service.
(2) Fuel usage and lost and unaccounted-for deductions
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.<PAGE>
<PAGE>
Page 2 of 2
EXHIBIT "B"
NOTES: (3) Applicable Surcharges:
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.
Gas Quality Control:
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, both
as set forth in the Tariff.
Gas Supply Transition:
The Gas Supply Transition Surcharge shall be
assessed pursuant to Article 21 of the General Terms
and Conditions as set forth in the Tariff.
ACA:
Transporter's applicable ACA Surcharge shall be
added to all discounted rates except that in no
event shall the discounted rate plus the ACA
Surcharge exceed Transporter's maximum rate as
stated in the Schedule of Rates in the Tariff.<PAGE>
Contract No. 35009000A
AMENDMENT
DATED: November 1, 1993
to
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-2
DATED: October 1, 1993
between
COLORADO INTERSTATE GAS COMPANY
and
GREELEY GAS COMPANY<PAGE>
AMENDMENT TO
FIRM TRANSPORTATION SERVICE AGREEMENT
RATE SCHEDULE TF-2
THIS AGREEMENT, made and entered into this 1st Day of
November, 1993, by and between COLORADO INTERSTATE GAS COMPANY,
hereinafter referred to as "Transporter," and GREELEY GAS
COMPANY, hereinafter referred to as "Shipper."
WHEREAS, Transporter and Shipper entered into a
Transportation Service Agreement ("Agreement") dated October 1,
1993, providing for the transportation by Transporter for Shipper
pursuant to 18 CFR 284.221 authority; and
WHEREAS, Transporter and Shipper desire to amend the
Agreement effective November 1, 1993, to revise the Primary
Points of Delivery as stated in Exhibit "A" to the Agreement;
NOW, THEREFORE, in consideration of the premises and the
mutual covenants hereinafter contained, Transporter and Shipper
agree to amend the Agreement as follows:
Effective November 1, 1993, Exhibit "A" shall be deleted
in its entirety and the attached Exhibit "A" shall be substituted
therefor.
This Amendment shall be effective as of November 1, 1993,
and except as herein amended, the Agreement shall in all respects
remain in full force and effect.<PAGE>
IN WITNESS WHEREOF, the Parties have executed this
Amendment.
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By /s/ D. J. Zinko
-----------------------------
D. J. Zinko
Senior Vice President
GREELEY GAS COMPANY
(Shipper)
ATTEST:
By /s/ Gary L. Schlessman
-----------------------------
By Gary L. Schlessman
----------------------- --------------------------------
Title: (Print or type name)
President
--------------------------------
(Print or type title)
2<PAGE>
Page 1 of 2
EXHIBIT "A"
to
FIRM TRANSPORTATION SERVICE AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
GREELEY GAS COMPANY (Shipper)
Agreement Dated: October 1, 1993
Amendment Dated: November 1, 1993
1. Shipper's Maximum Delivery Quantity: 1,408 Dth per Day (Note
3).
Point of Maximum
Receipt Quantity Receipt
Primary Point(s) of Receipt (Dth per Day) Pressure
(Note 1) (Note 2) p.s.i.g.
Lakin Master Meter 1,408 900
Point of
Delivery Quantity Delivery
Primary Point(s) of Delivery (Dth per Day) Pressure
(Note 1) (Note 4) p.s.i.g.
Canon City Group (Note 5)
Canon City 1,408 (Note 6) (Note 7)
Colorado State Penitentiary 591 (Note 6) 100
Florence City Gate 1,408 (Note 6) 60
Penrose City Gate 394 (Note 6) 60
Penrose South 74 (Note 6) Line Pressure
Portland City Gate 1,408 (Note 6) 100
Pritchett City Gate 295 (Note 6) 150
Fremont County Industrial Park 148 (Note 6) Line Pressure
The Piggery 15 (Note 6) Line Pressure
Engineer's Station 476+78 15 (Note 6) Line Pressure
Penrose PBS-2 295 (Note 6) Line Pressure<PAGE>
Page 2 of 2
EXHIBIT "A"
NOTES: (1) Information regarding Points of Receipt and Points
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) Point of Receipt Quantities may be increased by an
amount equal to Transporter's effective fuel
reimbursement.
(3) In Docket No. RP93-99, CIG's conversion to a thermal
tariff is subject to review as to methodology,
factors, or any other issue involved in the
transition from a volumetric basis to a thermal
basis. Should such review result in a change in the
basis upon which the thermal quantities used in this
service agreement were determined, such thermal
quantities shall be adjusted as required.
(4) The sum of the Primary Point of Delivery Quantities
shall be equal to or less than Shipper's MDQ.
(5) Transporter's obligation to make deliveries at all
Primary Points of Delivery included in the Canon
City Group shall be limited in the aggregate to
1,408 Dth per Day.
(6) Transporter's obligation to make deliveries at this
Point of Delivery under this Agreement and all other
Firm Service Agreements shall be limited in the
aggregate to the following volumes, or the meter
capacity, whichever is less.
Canon City 11,855
Colorado State Penitentiary 591
Florence City Gate 2,265
Penrose City Gate 394
Penrose South 74
Portland City Gate 3,073
Pritchett City Gate 295
Fremont County Industrial Park 148
The Piggery 15
Engineer's Station 476+78 15
Penrose PBS-2 295
(7) Line pressure but not less than 100 p.s.i.g.<PAGE>
EXHIBIT 10.7(a)
AMARILLO SUPPLY AGREEMENT
This Agreement is made and entered into effective the 2nd
day of January 1993 by and between Mesa Operating Limited
Partnership, a Delaware limited partnership, ("SELLER") and
Energas Company, a division of Atmos Energy Corporation, a Texas
Corporation ("BUYER").
WITNESSETH:
WHEREAS, SELLER and BUYER are the respective successors to
that certain Agreement between Amarillo Oil Company and Amarillo
Gas Company, dated June 27, 1949, ("Amarillo Supply Contract");
and
WHEREAS, SELLER and BUYER desire to consolidate the
Amarillo Supply Contract and all amendments thereto into a single
document which reflects the current agreement between SELLER and
BUYER;
Now THEREFORE, in consideration of the premises and mutual
covenants and agreements contained herein as well as other
valuable consideration, the sufficiency and receipt of which are
hereby acknowledged, SELLER and BUYER mutually covenant and agree
as follows:
I. Amarillo Supply Contract Superseded: Effective January
2, 1993, all provisions of the Amarillo Supply Contract, and all
amendments thereto are terminated and are hereby superseded by
the terms of this Agreement.
II. Supply of Gas: (a) SELLER agrees and obligates itself
to sell and deliver to BUYER, and BUYER agrees to purchase and
take from SELLER and pay for, all volumes of gas made available
by SELLER to BUYER and which are required by BUYER to supply its <PAGE>
present and future domestic and commercial customers located in
the City of Amarillo, Texas, and its environs.
(b) In order that BUYER may be assured of an adequate and
permanent supply of gas under the terms and provisions hereof
with which to meet its present and future market requirements, as
above defined, BUYER shall have first call upon the residue gas
attributable to the gas now owned or controlled by SELLER under
and by virtue of that certain agreement dated January 3, 1928,
between the Amarillo Oil Company, predecessor in interest of the
SELLER and Canadian River Gas Company, predecessor in interest to
Colorado Interstate Gas Company as amended from time to time (the
"B" Contract). BUYER's first call rights to receive "B" Contract
residue gas in preference to SELLER's rights to sell such gas to
customers other than Energas shall be subject to the "B"
Contract, as amended by that certain Production Allocation
Agreement dated January 1, 1991, and that certain instrument
entitled Amendment to "B" Contract and Production Allocation
Agreement dated January 1, 1993 (collectively, the PAA) between
the SELLER and Colorado Interstate Gas Company and shall apply
only to such volumes of residue gas as are required to serve
BUYER's domestic and commercial customers in the City of Amarillo
and its environs; provided, however, that SELLER shall not be
obligated to deliver to BUYER on a daily basis volumes in excess
of the available residue gas attributable to 100 MMcf per day of
SELLER's production under the "B" Contract.
(c) SELLER will make no sale, transfer, assignment, or
other disposition of its "B" Contract gas rights as are required
to serve BUYER's domestic and commercial customers in the City of
- 2 - <PAGE>
Amarillo and its environs, except subject to the first call
rights described herein.
(d) That in the event SELLER shall default in the
performance of any of its obligations hereunder, BUYER shall be
subrogated to and entitled to exercise and enforce all the
rights, privileges, remedies of SELLER against any and all
persons and corporations through or from which SELLER's "B"
Contract gas is obtained.
III. Delivery Points and Pressure: The gas purchased
hereunder by BUYER shall be delivered by SELLER to BUYER at the
outlet discharge header of SELLER's Fain Gas Plant and at such
other points as may be mutually agreed upon between BUYER and
SELLER.
During periods when the volume of gas demand on BUYER's
system is less than or equal to the maximum volume of gas SELLER
is required to deliver to BUYER's system pursuant to Article II
hereof, the deliveries at the outlet of SELLER's Fain Gas Plant
as aforesaid shall be made at pressures not less than 190# per
square inch gauge and not in excess of 400# per square inch
gauge, as required from time to time by BUYER.
Notwithstanding the foregoing, if during periods when the
volume of gas demand on BUYER's system is more than the maximum
volume of gas SELLER is required to deliver to BUYER's system
pursuant to Article II hereof, then SELLER's deliveries may be
made at pressures less than 190# per square inch gauge. In the
event BUYER desires a minimum delivery pressure in excess of 190#
per square inch gauge then same shall be subject to negotiations
between the parties, provided that BUYER shall give SELLER one
- 3 - <PAGE>
year's advance written notice requesting such future pressure.
The deliveries made at points other than the outlet of SELLER's
Fain Gas Plant shall be made at pressures suitable to BUYER but
within the then existing limitations of SELLER's supply at such
points.
IV. Prices and Charges:
(a) Prices: Except as provided in Section (c) of this
Article IV, all gas delivered to BUYER by SELLER pursuant to this
Agreement shall be priced as follows:
A composite price per Mcf for gas delivered hereunder shall
be determined by a formula comprised of a Fixed Price component
which will be utilized for seventy percent (70%) of the composite
price, and a Spot Price component which will be utilized for
thirty percent (30%) of the composite price. Such formula price
will be in effect for a period beginning January 2, 1993 and
ending December 31, 1997. The pricing of gas to be delivered
hereunder in periods subsequent to December 31, 1997 is described
in Section (c) of this Article IV.
The composite price per Mcf to be paid each month by BUYER
shall be calculated as follows:
Monthly Price = {FP x 0.7} + {(SP + $0.10) (0.3)}
where:
FP = Fixed Price component
SP = Spot Price component
The Fixed Price component shall be determined for each year
by establishing a Fixed Price of $2.71 per Mcf for the initial
year of 1993. The Fixed Price shall be redetermined for each
subsequent year by escalating the prior year's Fixed Price by
- 4 - <PAGE>
five percent (5%) for calendar years 1994 and 1995, and seven and
one-half percent (7.5%) for calendar years 1996 and 1997.
The Fixed Price component of the formula price is thus
calculated as follows:
Year Fixed Price Component Per Mcf
1993 $2.71 = 1993 Fixed Price
1994 $2.71 x 1.05 = 1994 Fixed Price
1995 1994 Fixed Price x 1.05 = 1995 Fixed Price
1996 1995 Fixed Price x 1.075 = 1996 Fixed Price
1997 1996 Fixed Price x 1.075 = 1997 Fixed Price
The Spot Price component shall be determined monthly and
shall be comprised of the hereinafter described Spot Index Price,
plus a fee of $0.10. The parties shall use the first issue of
Natural Gas Week published each month to determine the Spot Index
Price. The Spot Index Price shall be that price reported in the
table titled "Gas Price Report" under the subheadings "Texas,
West, Spot, Delivered to Pipeline" in the "Bid Week" column for
the month of actual delivery. If such index ceases to be
published or the parties mutually agree that the index ceases to
reasonably reflect the spot price for gas, the parties shall
attempt to agree on a substitute index giving due regard to the
purpose and intent in selecting this original index. If the
parties cannot mutually agree on a substitute index or cannot
agree that the index in effect at the time has ceased to
reasonably reflect the spot price for gas delivered hereunder,
then in either of such events, the parties agree that they shall
submit the issue of the alternate selection of an appropriate
index to binding arbitration to be conducted by and under the
- 5 - <PAGE>
then existing rules of the American Arbitration Association
("AAA") within thirty (30) days of written notification from one
party to the other; provided, however, that such arbitration
shall not be conducted more often than once every two years in
the event of disagreement as to whether a particular index
reasonably reflects the spot price for gas. The question of
selection of an index brought about by the cessation of
publication of an index being used may be submitted to
arbitration as often as is necessary. The selection of
arbitrators will be conducted pursuant to the process described
under Section (c) of Article IV below and the three arbitrators
so chosen will be required to issue within thirty (30) days from
the date of their selection their decision on the appropriate
index to be utilized.
The parties agree that until a new index has been
established, the applicable Spot Price to be used on an interim
basis each month will be the Spot Price for the same month of the
prior year plus 5%. As soon as the new index is established, it
will become retroactively effective as of the first day of the
month following the month during which the thirty (30) day
written notification was received by the second party and any
required adjustment will be made within ninety (90) days.
(b) Tax Surcharges: It is understood and agreed that the
prices for gas provided for herein shall be increased or
decreased, as the case may be, to reflect the full amount of any
new or additional, or of any increase or decrease in present
rates of severance, gross production, gross receipts, and excise
taxes of any nature whatsoever or similar taxes which, after
- 6 - <PAGE>
January 1, 1993, may be imposed, levied or assessed by any
governmental authority upon the gas sold hereunder, whether or
not the same shall be paid or payable directly or indirectly by
SELLER. Taxes being reimbursed by BUYER to SELLER as of December
31, 1992 will continue to be reimbursed by BUYER and shall be
calculated in the same manner as such taxes were calculated on
December 31, 1992. Applicable laws, rulings or orders
increasing, decreasing or creating any such tax shall be binding
and conclusive upon BUYER until such time as the invalidity
thereof has been finally established by the decision of a court
of competent jurisdiction. In no event, however, shall the
provisions of this paragraph be applied or construed so as to
decrease the prices for gas sold by virtue of this Agreement
below the applicable prices then in effect pursuant to Sections
(a) or (c) of this Article IV. In the event any tax included
within this Section is legally determined to be invalid or
unlawfully collected and a refund thereof is subsequently
received by SELLER, then SELLER agrees to return to BUYER such
portion of the refund as may have been applicable to purchases
made by BUYER and paid by BUYER to SELLER, less SELLER's costs of
recovering such refund.
(c) Future price determinations: The price redetermi-
nation procedure set forth hereinafter shall be employed for each
two year period of the remaining term of the Amarillo Supply
Agreement, following the formula pricing period (1993 - 1997)
outlined in (a) above. On or before September 1, 1997, and on or
before September 1 each two years thereafter, BUYER and SELLER
shall meet to determine the price(s) or pricing formula to be in
- 7 - <PAGE>
effect during each subsequent two year period, commencing January
1, 1998. If the parties have not redetermined the price(s) or
agreed upon a pricing formula by September 1, 1997, and each
September 1 each two years thereafter, then the parties agree
that they shall submit such pricing determination to binding
arbitration to be conducted by, and under the then existing rules
of the AAA within thirty (30) days of written notification from
one party to the other. Within sixty (60) days of such
submission, three arbitrators shall be chosen by the parties from
panels supplied by the AAA. If the parties are unable to select
three arbitrators during such period, the selection of the
remaining arbitrator(s) shall be conducted pursuant to the rules
of the AAA governing the selection of arbitrator(s) when the
parties have failed to do so.
The arbitrators so chosen shall be instructed to determine,
within ninety (90) days from their selection, a reasonable
price(s) or pricing formula based on the particular character-
istics of the supply under the Amarillo Supply Agreement at the
time of the price redetermination for the two year period
beginning January 1, 1998, or any subsequent two year period, for
which the parties are unable to agree upon a price(s) or pricing
formula. Essential characteristics to be considered by the
arbitrators include the following:
1) The annual volume normally purchased from SELLER by
BUYER.
2) The daily volume made available from SELLER to BUYER
during the various seasons of the year.
- 8 - <PAGE>
3) The average daily volume utilized by BUYER during the
course of a year.
4) The load factor and daily and seasonal swings of
BUYER's Amarillo system demands.
5) The remaining term of the Amarillo Supply Agreement.
The parties agree that until a new price(s) or pricing
formula has been established, the applicable composite price for
each month to be used on an interim basis will be the same as the
applicable composite price established for the same month of the
prior year plus 5%. As soon as the new price(s) or pricing
formula is established, it will become retroactively effective as
of the first day of the new pricing period and any required
adjustment will be made within ninety (90) days.
V. Quality: All of the gas sold hereunder shall be
gasoline plant residue gas and shall have the following
characteristics:
(a) It shall contain not more than twenty-five one
hundredths (0.25) grain of hydrogen sulphide per 100 cubic feet
measured as herein provided;
(b) The dew point at delivery pressure shall be at least
ten degrees below the existing ground temperature at pipeline
depth;
(c) It shall be commercially free of dust, gums, and other
solid matter;
(d) The gas shall have a monthly weighted gross heating
value of not less than nine hundred fifty (950) British Thermal
Units per cubic foot.
- 9 -<PAGE>
VI. Meters and Measurement: (a) The volume of gas
delivered hereunder shall be measured by orifice meters installed
and maintained as prescribed in the Gas Measurement Committee
Report No. 3, (ANSI/API-2530, Second Edition) of the American Gas
Association and as revised from time to time. (AGA Report No. 3)
(b) BUYER shall maintain and operate at or near the
various points of delivery, suitable meters and auxiliary
equipment to properly measure the volumes of gas being delivered.
All such measuring equipment shall remain the sole property of
BUYER but the SELLER shall have access to said metering equipment
at all reasonable times. The reading, calibration, and adjusting
of said meters shall be done by the employees or agents of BUYER
and charts and records from such metering equipment shall remain
the property of BUYER, but upon request of SELLER, BUYER will
submit to SELLER the records and charts from said metering
equipment together with calculations therefrom for SELLER'S
inspection and verification subject to return by SELLER within a
reasonable period of time.
(c) SELLER may, at its option and at its sole cost and
expense, install and operate check metering equipment, but the
metering equipment of BUYER shall be used for determining the
amounts of gas delivered under this Agreement.
(d) The unit of measurement for all gas deliverable under
this Agreement shall be one thousand (1,000) cubic feet of
natural gas at a base temperature of sixty (60) degrees
Fahrenheit and at a base pressure of 14.65 pounds absolute and
the readings and registrations of all metering equipment shall be
- 10 - <PAGE>
computed into such units in accordance with AGA Report No. 3
referenced above.
(e) For the purpose of measurement the average atmospheric
pressure shall be assumed to be thirteen (13.0) pounds
irrespective of the actual elevation of the delivery point above
sea level or of variations in the barometric pressure from time
to time.
(f) For meters of the orifice type, corrections shall be
made for the following factors:
1) Flowing temperature variation from 60 degrees
Fahrenheit;
2) Deviation of the gas from Boyle's Law;
3) Calculations shall be based on specific gravities
determined by chromatograph analysis of the flowing gas stream
for the current month, based upon either a continuous composite
sample at the tailgate of the Fain Plant or a proportional to
flow composite sample at the tailgate of the Fain Plant.
(g) All determinations of physical characteristics, and
meter tests shall be made with standard apparatus and using
generally accepted industry methods at such times and places as
in accordance with good practice may be agreed upon from time to
time between SELLER and BUYER.
VII. Billing and Payment: SELLER shall render to BUYER,
on or before the tenth (10th) day of each month a statement
showing the volume of gas delivered to BUYER during the calendar
month immediately preceding and the amount of payment or payments
then due from BUYER to SELLER for such gas delivered. In the
event an error is discovered in the amount billed in any
- 11 - <PAGE>
statement rendered by SELLER, such error shall be adjusted within
thirty (30) days after a claim is made therefore, but in any
event within twenty-four (24) months from the date of such
statement. Failure to make a written request for a required
adjustment within the twenty-four (24) month period shall be
deemed a waiver of that adjustment by the party having such
adjustment rights. Both SELLER and BUYER shall have the right to
examine, at reasonable times, books, records and charts of the
other to the extent necessary to verify the accuracy of any
statement, charge or computation made under or pursuant to any of
the provisions hereof.
BUYER agrees to pay SELLER at its office in Amarillo,
Texas, or at such other address designated in writing by SELLER,
on or before the 20th day of each month for all gas delivered
hereunder during the preceding month according to the gas
measurements and computations and at the prices hereinbefore
provided for and billed on said monthly statement. Should BUYER
fail to pay any amount due SELLER when such amount is due and
such failure to pay continues for sixty (60) days, then SELLER
may suspend deliveries of gas, but the exercise of such right
shall be in addition to any and all other remedies available to
SELLER.
VIII. Force Majeure: In the event of either party being
rendered unable wholly or in part by force majeure to carry out
its obligations under this Agreement other than to make payments
of amounts due hereunder, it is agreed that on such party giving
notice and full particulars of such force majeure in writing or
by telegraph to the other party as soon as possible after the
- 12 - <PAGE>
occurrence of the cause relied on, then the obligations of the
party giving such notice, so far as they are affected by such
force majeure, shall be suspended during the continuance of any
inability so caused but for no longer period, and such cause
shall, so far as possible, be remedied with all reasonable
dispatch.
The term "force majeure" as employed herein shall mean acts
of God, strikes, lockouts or other industrial disturbances, acts
of the public enemy, wars, blockades, insurrections, riots,
epidemics, landslides, lightning, earthquakes, fires, storms,
floods, washouts, arrests and restraint of rulers and people,
civil disturbances, explosions, breakage or accident to machinery
or lines of pipe, the necessity for making repairs and/or
alterations in machinery or lines of pipe, freezing of wells or
lines of pipe, sudden partial or entire failure of natural gas
wells, and any other cause, whether of the kind herein
enumerated, or otherwise, not within the control of the party
claiming suspension and which by the exercise of due diligence
such party is unable to overcome.
IX. Responsibility for Handling: As between the parties
hereto, SELLER shall be in control and possession of the gas
deliverable hereunder and responsible for any damage or injury
caused thereby until the same shall have been delivered to BUYER,
after which delivery BUYER shall be deemed to be in exclusive
control and possession thereof and responsible for any such
injury or damage.
X. Termination for Default: If either party shall fail to
perform the covenants or obligations imposed upon it under and by
- 13 - <PAGE>
virtue of this Agreement, then and in such event the other party
may, at its option, terminate this Agreement by proceeding as
follows:
The party not in default shall cause written notice to be
served on the party in default, stating specifically the cause
for terminating this Agreement and declaring it to be the
intention of the party giving the notice to terminate the same;
thereupon the party in default shall have thirty (30) days after
the service of the aforesaid notice in which to remedy or remove
the cause or causes stated in the notice for terminating this
Agreement and if, within said period of thirty (30) days, the
party in default does so remove and remedy said cause or causes
and fully indemnifies the party not in default for any and all
consequences of such breach, then such notice shall be withdrawn
and this Agreement shall continue in full force and effect. In
case the party in default does not so remedy and remove the cause
or causes and/or does not indemnify the party giving the notice
for any and all consequences of such breach within said period of
thirty (30) days, and if the party giving the notice does not
withdraw the notice, then this Agreement shall become null and
void from and after the expiration of said period. Any
cancellation of this Agreement pursuant to the provisions of this
article shall be without prejudice to any right of the party not
in default to collect any amounts then due to it and without
waiver of any other remedy to which the party not in default may
be entitled for violation of this Agreement.
XI. Successors and Assigns: This Agreement shall inure to
the benefit of and be binding upon the successors and assigns of
- 14 - <PAGE>
the parties hereto, and is intended solely for the benefit of
BUYER and SELLER and their respective successors and assigns and
not for the benefit of any third parties. Whenever the name of
any corporation or partnership is used herein it shall include
the successors and assigns of such corporation or partnership,
but neither party hereto may assign this Agreement without the
written consent of the other being first had and obtained, which
written consent shall not be unreasonably withheld.
XII. Term: This Agreement shall be in force and effect
from and after January 2, 1993, and shall continue in force and
effect for so long as SELLER has merchantable quantities of gas
available hereunder for sale to BUYER.
XIII. Miscellaneous: (a) This Agreement shall be
governed by and construed in accordance with the laws of the
State of Texas, excluding any conflicts of law, rule, or other
principle which might refer such construction to the laws of
another state. All terms and conditions of this Agreement were
prepared jointly by the SELLER and BUYER and not by any party to
the exclusion of the other.
(b) This Agreement may not be modified or amended except
by the written agreement of the parties hereto.
(c) No waiver by either party hereto of any default of the
other party or breach of any provision of the other party under
this Agreement shall operate as, or be deemed to be, a waiver of
any other or subsequent default or breach, whether of a like or
different nature.
(d) Each provision and term of this Agreement is intended
to be several. If any term or provision hereof is held to be
- 15 - <PAGE>
illegal or invalid by a court of competent jurisdiction, such
illegality or invalidity shall not affect in any way the validity
or legality of the remaining terms or provisions.
IN WITNESS WHEREOF, the parties hereto have executed this
Amarillo Supply Agreement effective as of the date first above
written.
MESA OPERATING LIMITED PARTNERSHIP
By Pickens Operating Co.,
General Partner
By /s/ s. Leonard Hruzek, Jr.
-----------------------------
S. Leonard Hruzek, Jr.,
Vice President
Date September 2, 1993
-----------------------------
ENERGAS COMPANY, a division of
Atmos Energy Corporation
By /s/ Toby A. Priolo
-----------------------------
Toby A. Priolo,
Vice President
Date August 27, 1993
-----------------------------
- 16 -<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITOR
We consent to the incorporation by reference in the Registration
Statements (Form S-8 No. 33-68852, Form S-8 No. 2-89113, Form S-3
No. 33-58220, and Form S-3 No. 33-70212) of Atmos Energy
Corporation and in the related Prospectuses of our report dated
November 9, 1994, with respect to the consolidated financial
statements and schedules of Atmos Energy Corporation included in
this Annual Report (Form 10-K) for the year ended September 30,
1994.
ERNST & YOUNG LLP
Dallas, Texas
December 15, 1994
1<PAGE>
<TABLE> <S> <C>
<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, 1994 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-30-1994
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 327,407
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 53,298
<TOTAL-DEFERRED-CHARGES> 35,973
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 416,678
<COMMON> 77
<CAPITAL-SURPLUS-PAID-IN> 102,456
<RETAINED-EARNINGS> 47,023
<TOTAL-COMMON-STOCKHOLDERS-EQ> 149,556
0
0
<LONG-TERM-DEBT-NET> 138,303
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 18,100
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 4,000
0
<CAPITAL-LEASE-OBLIGATIONS> 5,741
<LEASES-CURRENT> 553
<OTHER-ITEMS-CAPITAL-AND-LIAB> 100,425
<TOT-CAPITALIZATION-AND-LIAB> 416,678
<GROSS-OPERATING-REVENUE> 499,808
<INCOME-TAX-EXPENSE> 8,102
<OTHER-OPERATING-EXPENSES> 465,240
<TOTAL-OPERATING-EXPENSES> 473,342
<OPERATING-INCOME-LOSS> 26,466
<OTHER-INCOME-NET> 503
<INCOME-BEFORE-INTEREST-EXPEN> 26,969
<TOTAL-INTEREST-EXPENSE> 12,290
<NET-INCOME> 14,679
0
<EARNINGS-AVAILABLE-FOR-COMM> 14,679
<COMMON-STOCK-DIVIDENDS> 12,732
<TOTAL-INTEREST-ON-BONDS> 1,916
<CASH-FLOW-OPERATIONS> 41,224
<EPS-PRIMARY> .97
<EPS-DILUTED> .97
</TABLE>
