UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
|
COMMISSION FILE NUMBER 1-10042
ATMOS ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS AND VIRGINIA 75-1743247
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)
THREE LINCOLN CENTRE, SUITE 1800 75240
5430 LBJ FREEWAY, DALLAS, TEXAS (Zip code)
(Address of principal executive offices)
|
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(972) 934-9227
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE 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. [ ]
Indicate by check whether the recipient is an accelerated filer (as defined
in Exchange Act Rule 12b-2. Yes [X] No [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was $1,191,025,336 as of October 31, 2003. On October 31, 2003
the registrant had 51,534,331 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Definitive Proxy Statement to be filed for the
Annual Meeting of Shareholders on February 11, 2004 are incorporated by
reference into Part III of this report.
PART I
The terms "we," "our," "us," "Atmos" and "Atmos Energy" refer to Atmos
Energy Corporation and its subsidiaries, unless the context suggests otherwise.
The abbreviations "Mcf," "MMcf" and "Bcf" mean thousand cubic feet, million
cubic feet and billion cubic feet.
ITEM 1. BUSINESS
OVERVIEW
Atmos Energy Corporation and its subsidiaries are engaged primarily in the
natural gas utility business as well as certain natural gas non-utility
businesses. We distribute natural gas through sales and transportation
arrangements to approximately 1.7 million residential, commercial, public
authority and industrial customers through our six regulated utility divisions,
which cover service areas located in the following 12 states: Colorado, Georgia,
Illinois, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Tennessee,
Texas and Virginia. In addition, we transport natural gas for others through our
distribution system.
Through our non-utility businesses, we provide natural gas management and
marketing services to industrial customers, municipalities and other local gas
distribution companies in 18 states. We also supplement natural gas used by our
customers through natural gas storage fields that we own or hold an interest in
and which are located in Kansas, Kentucky, Louisiana and Mississippi. We market
natural gas to industrial and agricultural customers primarily in west Texas and
to industrial customers in Louisiana. Finally, we construct electric power
generating plants and associated facilities to meet peak load demands and lease
or sell them to municipalities and industrial customers.
Our operations are divided into three segments:
- the utility segment, which includes our related natural gas distribution
and sales operations,
- the natural gas marketing segment, which includes a variety of natural
gas management services and
- the other non-utility segment, which includes our storage services and
our electric power plant construction and leasing services.
Financial information relating to our operating segments is contained in
Note 17 to the consolidated financial statements.
STRATEGY
Our overall strategy is to:
- accelerate growth through profitable acquisitions;
- improve the quality and consistency of earnings growth, while operating
the natural gas utility and non-utility businesses exceptionally well and
- enhance and strengthen a culture built on our core values.
Over the last five years, we have accelerated our growth through several
acquisitions including our acquisition of the remaining 55 percent interest in
Woodward Marketing, L.L.C. that we did not already own in April 2001, the assets
of Louisiana Gas Service Company (LGS) in July 2001 and Mississippi Valley Gas
Company (MVG) in December 2002.
We have experienced 20 consecutive years of increasing dividends and
consistent earnings growth after giving effect to our mergers. We have achieved
this record of growth while operating our utility operations efficiently by
managing our operating and maintenance expense; leveraging our technology, such
as our 24 hour call center, to achieve more efficient operations; focusing on
regulatory rate proceedings to increase revenue as our costs increased;
mitigating weather-related risks through weather-normalized rates in some
jurisdictions and disposing of non-growth assets. Additionally, we have
strengthened our non-utility business
1
by essentially eliminating speculative trading activities and actively pursing
opportunities to increase the amount of storage available to us to help mitigate
the effects of weather on our trading activities.
Our core values include focusing on our employees and customers while
conducting our business with honesty and integrity. We are strengthening our
culture through continuous communication with our employees and enhanced
training.
UTILITY SEGMENT
We operate our utility segment through six regulated natural gas utility
divisions. Effective October 1, 2002, we united our gas distribution utility
operations under the Atmos Energy brand. The following presents our six natural
gas utility divisions and their former operating names:
- Atmos Energy Colorado-Kansas Division (formerly Greeley Gas Company),
- Atmos Energy Kentucky Division (formerly Western Kentucky Gas Company),
- Atmos Energy Louisiana Division (formerly Atmos Energy Louisiana Gas
Company),
- Atmos Energy Mid-States Division (formerly United Cities Gas Company),
- Atmos Energy Texas Division (formerly Energas Company) and
- Mississippi Valley Gas Company Division (acquired in December 2002).
Our natural gas utility distribution business is seasonal and dependent on
weather conditions in our 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 gas sales during the winter months will vary with the
temperatures during these months. The seasonal nature of our sales to
residential and commercial customers is partially offset by our sales in the
spring and summer months to our agricultural customers in Texas, Colorado and
Kansas who use natural gas to operate irrigation equipment.
In addition to weather, our revenues are affected by the cost of natural
gas and economic conditions in the areas that we serve. Higher gas costs, which
we are generally able to pass through to our customers under purchased gas
adjustment clauses, may cause customers to conserve, or, in the case of
industrial customers, to use alternative energy sources.
The effects of weather that is above or below normal are partially offset
through weather normalization adjustments (WNA) in certain service areas. WNA
allows us to increase the base rate portion of customers' bills when weather is
warmer than normal and decrease the base rate when weather is colder than
normal. As of September 30, 2003, we have WNA in the following service areas for
the following periods, which cover approximately 658,000 or 39 percent of our
meters in service:
Tennessee................................................... November -- April
Georgia..................................................... October -- May
Mississippi................................................. November -- May
Kentucky.................................................... November -- April
Kansas(1)................................................... October -- May
Amarillo, Texas(1).......................................... October -- May
|
(1) Effective for the 2003-2004 winter heating season
We receive gas deliveries in our utility operations through 36 pipeline
transportation companies, both interstate and intrastate, to satisfy our sales
market requirements. The pipeline transportation agreements are firm and many of
them have "pipeline no-notice" storage service which provides for daily
balancing between system requirements and nominated flowing supplies. These
agreements have been negotiated with the shortest term necessary while still
maintaining our right of first refusal.
2
We purchase our gas supply from various producers and marketers. Supply
arrangements are contracted on a firm basis with various terms at market prices.
The firm supply consists of both base load and swing supply quantities. Base
load quantities are those that flow at a constant level throughout the month and
swing supply quantities provide the flexibility to change daily quantities to
match increases or decreases in requirements related to weather conditions.
Except for local production purchases, we select suppliers through a competitive
bidding process by requesting proposals from suppliers that have demonstrated
that they can provide reliable service. We select these suppliers based on their
ability to deliver gas supply to our designated firm pipeline receipt points at
the lowest cost. Our major suppliers during fiscal 2003 were Anadarko Energy
Services, BP Energy Company, Cinergy Marketing and Trading, Duke Energy Trading
and Marketing, ONEOK Energy Marketing, Pioneer Natural Resources, Prior Energy
Corporation, Tenaska Marketing and Woodward Marketing, L.L.C., one of our
natural gas marketing subsidiaries. We do not anticipate problems with obtaining
additional gas supply as needed for our customers.
We also contract for storage service in underground storage facilities on
many of the interstate pipelines serving us.
Our distribution systems have experienced aggregate peak day deliveries of
approximately 2.0 Bcf per day. To maintain our deliveries to high priority
customers, we have the ability and have exercised our right, to curtail
deliveries to certain customers under the terms of interruptible contracts,
applicable state statutes or regulations.
The following is a brief description of our six natural gas utility
divisions. Additional information for each division is presented under the
caption "Operating Statistics".
Atmos Energy Colorado-Kansas Division. Our Colorado-Kansas Division
operates in Colorado, Kansas and the southwestern corner of Missouri and is
regulated by each respective state's public service commission with respect to
accounting, rates and charges, operating matters and the issuance of securities.
We operate under terms of non-exclusive franchises granted by the various
cities. In May 2003, we received approval for WNA in Kansas which will be
effective October through May of each year beginning with the 2003-2004 winter
heating season. Colorado Interstate Gas Company, Williams Pipeline-Central,
Public Service Company of Colorado and Northwest Pipeline are the principal
transporters of the Colorado-Kansas Division's gas supply requirements.
Additionally, the Colorado-Kansas Division purchases substantial volumes from
producers that are connected directly to its distribution system.
Atmos Energy Kentucky Division. Our Kentucky Division operates in Kentucky
and is regulated by the Kentucky Public Service Commission, which regulates
utility services, rates, issuance of securities and other matters. We operate in
the various incorporated cities pursuant to non-exclusive franchises granted by
these cities. Sales of natural gas for use as vehicle fuel in Kentucky are
unregulated. We have been operating under a performance-based rate program since
July 1998, which was extended for another four years in 2002. Under the
performance-based program, we and our customers jointly share in any actual gas
cost savings achieved when compared to pre-determined benchmarks. Our rates are
also subject to WNA. The Kentucky Division's gas supply is delivered primarily
by Williams Pipeline-Texas Gas, Tennessee Gas, Trunkline, Midwestern Pipeline
and ANR.
Atmos Energy Louisiana Division. Our Louisiana Division operates in
Louisiana and includes the operations of the assets of Louisiana Gas Service
Company acquired in July 2001 and our previously existing Trans La Division. Our
Louisiana Division is regulated by the Louisiana Public Service Commission,
which regulates utility services, rates and other matters. We operate most of
our service areas pursuant to a non-exclusive franchise granted by the governing
authority of each area. Direct sales of natural gas to industrial customers in
Louisiana, who use gas for fuel or in manufacturing processes, and sales of
natural gas for vehicle fuel are exempt from regulation. Louisiana Intrastate
Gas Company, Acadian Pipeline, Gulf South and Williams Pipeline-Texas Gas
pipelines provide most of the Louisiana Division's natural gas requirements.
Atmos Energy Mid-States Division. Our Mid-States Division operates in
Georgia, Illinois, Iowa, Missouri, Tennessee and Virginia. In each of these
states, our rates, services and operations as a natural gas distribution company
are subject to general regulation by each state's public service commission. We
operate
3
in each community, where necessary, under a franchise granted by the
municipality for a fixed term of years. In Tennessee and Georgia, we have WNA
and a performance-based rate program, which provides incentives for us to find
ways to lower costs and share the cost savings with our customers. Our
Mid-States Division is served by 13 interstate pipelines; however, the majority
of the volumes are transported through East Tennessee Pipeline, Southern Natural
Gas, Tennessee Gas Pipeline and Columbia Gulf.
Atmos Energy Texas Division. Our Texas Division operates in Texas in three
primary service areas: the Amarillo service area, the Lubbock service area and
the West Texas service area. The governing body of each municipality we serve
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. We operate pursuant to non-exclusive franchises granted by
the municipalities we serve, which are subject to renewal from time to time. The
Railroad Commission of Texas has exclusive appellate jurisdiction over all rate
and regulatory orders and ordinances of the municipalities and exclusive
original jurisdiction over rates and services to customers not located within
the limits of a municipality. In August 2003, the Texas Division received
approval from the City of Amarillo, Texas, for WNA for its Amarillo service
area, which will be effective October through May of each year, beginning with
the 2003-2004 winter heating season. Our Texas Division receives transportation
service from ONEOK Pipeline. In addition, the Texas Division purchases a
significant portion of its natural gas supply from Pioneer Natural Resources
which is connected directly to our Amarillo, Texas distribution system.
Mississippi Valley Gas Company Division. Our Mississippi Valley Gas
Company Division, acquired in December 2002, operates in Mississippi and is
regulated by the Mississippi Public Service Commission with respect to rates,
services and operations. We operate under non-exclusive franchises granted by
the municipalities we serve. Since the acquisition, we have been operating under
a rate structure that allows us over a five year period to recover a portion of
our integration costs associated with the acquisition, and operations and
maintenance costs in excess of an agreed-upon benchmark. In addition, we are
required to file for rate adjustments based on our expenses every six months. We
also have WNA in Mississippi. This division's gas supply is delivered by Gulf
South Pipeline Company, Tennessee Gas Pipeline Company, Southern Natural Gas
Company, Texas Eastern Transmission, Texas Gas Transmission LLC, Trunkline Gas
Co. LLC and Enbridge Marketing LP.
NATURAL GAS MARKETING SEGMENT
Our natural gas marketing and other non-utility segments, which are
organized under Atmos Energy Holdings, Inc., have operations in 18 states.
Through September 30, 2003, Atmos Energy Marketing, LLC, together with its
wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana
Industrial Gas Company, Inc., comprised our natural gas marketing segment.
Effective October 1, 2003, our natural gas marketing segment was reorganized.
The operations of Atmos Energy Marketing, L.L.C and Trans Louisiana Industrial
Gas Company, Inc were merged into Woodward Marketing, L.L.C., which was renamed
Atmos Energy Marketing, LLC (AEM).
We acquired a 45 percent interest in Woodward Marketing, L.L.C. in July
1997 as a result of the merger of Atmos and United Cities Gas Company, which had
acquired that interest in May 1995. In April 2001, we acquired the remaining 55
percent interest that we did not own for 1,423,193 restricted shares of our
common stock.
AEM provides a variety of natural gas management services to
municipalities, natural gas utility systems and industrial natural gas consumers
primarily in the southeastern and midwestern states and to our Colorado-Kansas,
Kentucky, Louisiana and Mid-States divisions. These services primarily consist
of furnishing natural gas supplies at fixed and market-based prices, contract
negotiation and administration, load forecasting, gas storage acquisition and
management services, transportation services, peaking sales and balancing
services, capacity utilization strategies and gas price management through the
use of derivative products. In providing these services, AEM generates income
from its utility, municipal and industrial customers through negotiated prices
based on the volume of gas supplied to the customer. AEM also generates income
by taking advantage of the difference between near-term gas prices and prices
for future delivery as well as the daily movement of
4
gas prices by utilizing storage and transportation capacity that it controls.
Finally, AEM supplies our regulated operations with a portion of our natural gas
requirements on a competitive bid basis.
AEM's management of natural gas requirements involves the sale of natural
gas and the management of storage and transportation supplies under contracts
with customers generally having one to two year terms. At September 30, 2003,
AEM had a total of 750 industrial customers and 206 municipal customers. AEM
also sells natural gas to some of its industrial customers on a delivered burner
tip basis under contract terms from 30 days to two years.
OTHER NON-UTILITY SEGMENT
Our other non-utility segment consists primarily of the operations of Atmos
Pipeline and Storage, L.L.C. and Atmos Power Systems, Inc., which are
wholly-owned subsidiaries of Atmos Energy Holdings, Inc. Through Atmos Pipeline
and Storage, LLC, we own or have an interest in underground storage fields in
Kansas, Kentucky and Louisiana. We use these storage facilities to help meet
customer requirements during peak demand periods and to reduce the need to
contract for additional pipeline capacity to meet customer demand during peak
periods. We normally inject gas into pipeline storage systems and company owned
storage facilities during the summer months and withdraw it in the winter
months.
Through Atmos Power Systems, Inc. we construct and operate electric peaking
power generating plants and associated facilities and may enter into agreements
to either lease or sell these plants.
United Cities Propane Gas, Inc., a wholly-owned subsidiary of Atmos Energy
Holdings, Inc., owns an approximate 19 percent membership interest in U.S.
Propane L.P. (USP), a joint venture formed in February 2000 with other utility
companies. As of September 30, 2003, USP owned all of the general partnership
interest and approximately 26 percent of the limited partnership interest in
Heritage Propane Partners, L.P. a publicly traded marketer of propane through a
nationwide retail distribution network. Through our ownership in USP, we own an
approximate five percent indirect interest in Heritage Propane Partners, L.P. On
November 7, 2003, we announced that we and our utility partners had entered into
an agreement to sell our interest in USP, including the general partnership and
limited partnerships in Heritage Propane Partners, L.P., for $130.0 million. We
expect to receive approximately $24.7 million and to record a $4.4 million
pretax book gain upon closing of the transaction which is conditioned upon
regulatory and other approvals.
5
OPERATING STATISTICS
The following tables present certain operating statistics for our utility,
natural gas marketing and other non-utility segments for each of the five fiscal
years from 1999 through 2003. Certain prior year amounts have been reclassified
to conform to the current year presentation.
UTILITY SALES AND STATISTICAL DATA
YEAR ENDED SEPTEMBER 30
--------------------------------------------------------------
2003(1) 2002 2001(1) 2000 1999
---------- ---------- ---------- ---------- ----------
METERS IN SERVICE, END OF YEAR
Residential............................. 1,498,586 1,247,247 1,243,625 970,873 919,012
Commercial.............................. 151,008 122,156 122,274 104,019 98,268
Industrial.............................. 3,799 2,118 1,838 1,878 1,552
Agricultural............................ 9,514 10,576 11,182 12,381 12,777
Public authority and other.............. 9,891 7,244 7,404 7,448 6,386
---------- ---------- ---------- ---------- ----------
Total meters.......................... 1,672,798 1,389,341 1,386,323 1,096,599 1,037,995
========== ========== ========== ========== ==========
HEATING DEGREE DAYS(2)
Actual (weighted average)............... 3,473 3,368 4,124 2,096 3,374
Percent of normal....................... 101% 94% 115% 82% 85%
UTILITY SALES VOLUMES -- MMCF(3)
Gas Sales Volumes
Residential............................. 97,953 77,386 79,000 63,285 67,128
Commercial.............................. 45,611 35,796 36,922 30,707 31,457
Industrial.............................. 23,738 14,499 19,243 18,546 19,934
Agricultural............................ 7,884 10,988 7,070 1,412 967
Public authority and other.............. 9,326 5,875 6,892 5,520 5,793
---------- ---------- ---------- ---------- ----------
Total gas sales volumes............... 184,512 144,544 149,127 119,470 125,279
Utility transportation volumes............ 70,159 69,589 69,492 77,767 69,899
---------- ---------- ---------- ---------- ----------
Total utility throughput.................. 254,671 214,133 218,619 197,237 195,178
========== ========== ========== ========== ==========
UTILITY OPERATING REVENUES (000'S)(3)
Gas sales revenues
Residential............................. $ 873,375 $ 535,981 $ 788,902 $ 405,552 $ 349,691
Commercial.............................. 367,961 221,728 342,945 176,712 144,836
Industrial.............................. 151,969 70,164 120,770 90,966 70,322
Agricultural............................ 48,625 37,951 28,753 6,178 2,872
Public authority and other.............. 65,921 31,731 58,539 27,198 22,330
---------- ---------- ---------- ---------- ----------
Total utility gas sales revenues...... 1,507,851 897,555 1,339,909 706,606 590,051
Transportation revenues................... 30,461 28,786 28,750 28,726 26,933
Other gas revenues........................ 15,770 11,185 11,489 4,619 4,227
---------- ---------- ---------- ---------- ----------
Total utility operating revenues...... $1,554,082 $ 937,526 $1,380,148 $ 739,951 $ 621,211
========== ========== ========== ========== ==========
Utility average sales price per Mcf....... $ 8.17 $ 6.21 $ 8.99 $ 5.91 $ 4.71
Utility average transportation revenue per
Mcf..................................... $ 0.43 $ 0.41 $ 0.41 $ 0.37 $ 0.39
Utility average cost of gas per Mcf
sold.................................... $ 5.76 $ 3.87 $ 6.82 $ 3.67 $ 2.74
Employees(5).............................. 2,313 1,766 1,819 1,488 1,471
|
See footnotes following these tables.
6
UTILITY SALES AND STATISTICAL DATA BY DIVISION (4)
YEAR ENDED SEPTEMBER 30, 2003
--------------------------------------------------------------------------------------
COLORADO-
KANSAS KENTUCKY LOUISIANA MID-STATES TEXAS MISSISSIPPI TOTAL UTILITY
--------- -------- --------- ---------- -------- ----------- -------------
METERS IN SERVICE
Residential..................... 199,853 159,024 346,866 274,025 271,198 247,620 1,498,586
Commercial...................... 18,759 18,077 22,843 35,889 26,228 29,212 151,008
Industrial...................... 36 406 -- 729 933 1,695 3,799
Agricultural.................... 413 -- -- -- 9,101 -- 9,514
Public authority and other...... 1,584 1,661 930 750 2,208 2,758 9,891
-------- -------- -------- -------- -------- -------- ----------
Total......................... 220,645 179,168 370,639 311,393 309,668 281,285 1,672,798
======== ======== ======== ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual.......................... 5,704 4,364 1,735 3,843 3,487 2,243 3,473
Percent of normal............... 101% 101% 106% 101% 97% 101% 101%
SALES VOLUMES -- MMCF(3)
Gas Sales Volumes
Residential..................... 17,419 12,700 16,066 18,780 20,091 12,897 97,953
Commercial...................... 6,506 5,442 6,841 13,106 7,448 6,268 45,611
Industrial...................... 313 2,613 -- 8,332 4,149 8,331 23,738
Agricultural.................... 858 -- -- -- 7,026 -- 7,884
Public authority and other...... 1,233 1,559 867 277 2,342 3,048 9,326
-------- -------- -------- -------- -------- -------- ----------
Total......................... 26,329 22,314 23,774 40,495 41,056 30,544 184,512
Transportation Volumes............ 9,615 24,848 7,960 20,011 5,671 2,054 70,159
-------- -------- -------- -------- -------- -------- ----------
Total Throughput.................. 35,944 47,162 31,734 60,506 46,727 32,598 254,671
======== ======== ======== ======== ======== ======== ==========
OPERATING REVENUES (000'S)(3)..... $206,653 $177,613 $261,896 $374,725 $274,520 $258,675 $1,554,082
OTHER STATISTICS, AT YEAR END
Miles of pipe................... 6,341 3,840 7,952 7,790 13,261 6,083 45,267
Employees(5).................... 275 237 450 453 341 557 2,313
|
See footnotes following these tables.
7
YEAR ENDED SEPTEMBER 30, 2002
----------------------------------------------------------------------
COLORADO- MID-
KANSAS KENTUCKY LOUISIANA STATES TEXAS TOTAL UTILITY
--------- -------- --------- -------- -------- -------------
METERS IN SERVICE
Residential.............................. 196,320 158,296 346,369 273,166 273,096 1,247,247
Commercial............................... 18,602 18,017 22,709 35,925 26,903 122,156
Industrial............................... 41 409 -- 729 939 2,118
Agricultural............................. 423 -- -- -- 10,153 10,576
Public authority and other............... 1,594 1,657 934 810 2,249 7,244
-------- -------- -------- -------- -------- ----------
Total.................................. 216,980 178,379 370,012 310,630 313,340 1,389,341
======== ======== ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual................................... 5,373 4,346 1,543 3,644 3,259 3,368
Percent of normal........................ 95% 100% 90% 94% 92% 94%
SALES VOLUMES -- MMCF(3)
Gas Sales Volumes
Residential.............................. 15,660 10,802 15,117 16,245 19,562 77,386
Commercial............................... 5,948 4,611 6,442 11,599 7,196 35,796
Industrial............................... 365 1,931 -- 8,658 3,545 14,499
Agricultural............................. 1,474 -- -- -- 9,514 10,988
Public authority and other............... 1,190 1,314 847 287 2,237 5,875
-------- -------- -------- -------- -------- ----------
Total.................................. 24,637 18,658 22,406 36,789 42,054 144,544
Transportation Volumes..................... 8,917 25,063 8,029 20,355 7,225 69,589
-------- -------- -------- -------- -------- ----------
Total Throughput........................... 33,554 43,721 30,435 57,144 49,279 214,133
======== ======== ======== ======== ======== ==========
OPERATING REVENUES (000'S)(3).............. $154,718 $138,772 $188,092 $257,305 $198,639 $ 937,526
OTHER STATISTICS, AT YEAR END
Miles of pipe............................ 6,454 3,794 7,951 7,637 13,321 39,157
Employees(5)............................. 271 245 457 461 332 1,766
|
See footnotes following these tables.
8
NATURAL GAS MARKETING AND OTHER NON-UTILITY OPERATIONS SALES AND STATISTICAL
DATA
YEAR ENDED SEPTEMBER 30
-------------------------------------------------------
2003 2002 2001 2000 1999
---------- ---------- -------- -------- -------
CUSTOMERS, END OF YEAR
Industrial(7)....................... 750 641 531 -- --
Municipal(7)........................ 206 101 68 -- --
Propane(6).......................... -- -- -- -- 39,539
---------- ---------- -------- -------- -------
Total............................ 956 742 599 -- 39,539
========== ========== ======== ======== =======
NATURAL GAS MARKETING SALES
VOLUMES -- MMCF(3)(7)................. 294,785 273,692 98,869 -- --
PROPANE -- GALLONS (000'S)(6)......... -- -- -- 19,329 22,291
OPERATING REVENUES (000'S)(3)
Natural gas marketing............... $1,668,493 $1,031,874 $447,096 $ 929 $ --
Other non-utility................... 21,630 24,705 59,436 95,376 53,416
Propane revenues(6)................. -- -- -- 22,550 22,944
---------- ---------- -------- -------- -------
Total operating revenues......... $1,690,123 $1,056,579 $506,532 $118,855 $76,360
========== ========== ======== ======== =======
Equity in earnings of Woodward
Marketing L.L.C.(7)................. -- -- $ 8,062 $ 7,307 $ 7,156
========== ========== ======== ======== =======
Employees, at year end................ 88 83 62 28 164
|
Notes to preceding tables:
(1) The operational and statistical information includes the operations of LGS
since the July 1, 2001 acquisition date and the operations of MVG since the
December 3, 2002 acquisition date.
(2) A heating degree day is equivalent to each degree that the average of the
high and the low temperatures for a day is below 65 degrees. The colder the
climate, the greater the number of heating degree days. Heating degree days
are used in the natural gas industry to measure the relative coldness of
weather and to compare relative temperatures between one geographic area and
another. Normal degree days are based on 30-year average National Weather
Service data for selected locations. Degree day information for 2003, 2002
and 2001 is adjusted for service areas included in the Mid-States Division
and the Kentucky Division which have weather normalized operations. Degree
day information for 2003 is also adjusted for service areas included in the
Mississippi Valley Gas Company Division which has weather normalized
operations as well. Degree day information for 2000 and 1999 has not been
adjusted for service areas with weather normalized operations as that
information was not available.
(3) Sales volumes and revenues reflect segment operations, including
intercompany sales and transportation amounts.
(4) These tables present data for our six natural gas utility divisions. Their
operations include the regulated local distribution companies located in
their respective service areas. The operations of LGS are included in our
Louisiana Division since the July 1, 2001 acquisition date, and the
operations of MVG are included in our Mississippi Valley Gas Company
Division since the December 3, 2002 acquisition date.
(5) The number of utility employees excludes 504, 489, 480, 369 and 427 Atmos
shared services employees and 88, 83, 62, 28 and 164 other segment employees
in 2003, 2002, 2001, 2000 and 1999.
(6) Prior to August 2000, propane revenues and expenses were fully consolidated.
Subsequent to August 2000, the results of our propane operations are shown
on the equity basis.
(7) Through March 31, 2001 substantially all of our natural gas marketing
revenues and expenses are shown on the equity basis. Beginning April 1, 2001
natural gas marketing revenues and expenses are fully consolidated.
9
REGULATION
Each of our utility divisions is regulated by various state or local public
utility authorities. We are also subject to regulation by the United States
Department of Transportation with respect to safety requirements in the
operation and maintenance of our gas distribution facilities. Our distribution
operations are also subject to various state and federal laws regulating
environmental matters. From time to time we receive inquiries regarding various
environmental matters. We believe that our 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
would have a material adverse effect on us or our operations. All of our
environmental claims have arisen out of manufactured gas plant sites in
Tennessee, Iowa and Missouri and mercury contamination sites in Kansas. These
claims are more fully described in Note 13 to the consolidated financial
statements.
RATEMAKING ACTIVITY
OVERVIEW
The method of determining regulated rates varies among the states in which
our natural gas utility divisions operate. The regulators have the
responsibility of ensuring that utilities under their jurisdiction operate in
the best interests of customers while providing utility companies the
opportunity to earn a reasonable return on investment. In a general rate case,
the applicable regulatory authority, which is typically the state public utility
commission, establishes rates which allow a utility company an opportunity to
collect revenue from customers to recover the cost of providing utility service.
Rates established by regulatory authorities are adjusted for increases and
decreases in our purchased gas cost through purchased gas adjustment mechanisms.
Purchased gas adjustment mechanisms provide gas utility companies a method of
recovering purchased gas costs on an ongoing basis without filing a rate case to
address all of the utility's non-gas costs. These mechanisms are commonly
utilized when regulatory authorities recognize a particular type of expense,
such as purchased gas costs, that (i) is subject to significant price
fluctuations compared to the utility's other costs, (ii) represents a large
component of the utility's cost of service and (iii) is generally outside the
control of the gas utility. There is no margin generated through purchased gas
adjustments, but they do provide a dollar-for-dollar offset to increases or
decreases in utility gas costs. Although substantially all of our utility sales
to our customers fluctuate with the cost of gas that we purchase, utility gross
profit (which is defined as operating revenues less purchased gas cost) is
generally not affected by fluctuations in the cost of gas due to the purchased
gas adjustment mechanism. Additionally, certain jurisdictions have introduced
performance-based ratemaking adjustments to provide incentives to natural gas
utilities to minimize purchased gas costs through improved storage management
and use of financial hedges to lock in gas costs. Under the performance-based
ratemaking adjustment, purchased gas costs savings are shared between the
utility and the customer.
10
The following table summarizes certain information regarding our ratemaking
jurisdictions:
RATE BASE ALLOWED
DIVISION JURISDICTION (THOUSANDS)(1) RETURN ON EQUITY(1)
-------- ------------ -------------- -------------------
Colorado-Kansas......................... Colorado (2) 11.25% - 12.50%
Kansas (2) (2)
Kentucky................................ Kentucky (2) (2)
Louisiana............................... Louisiana $246,617 10.50% - 11.50%
Mid-States.............................. Georgia 38,451 11.50%
Illinois 24,564 11.56%
Iowa 5,000 11.00%
Missouri (2) 12.15%
Tennessee (2) (2)
Virginia 25,000 11.00%
Texas................................... Amarillo 36,844 12.00%
West Texas (2) (2)
Mississippi Valley Gas Company.......... Mississippi 175,206 10.20%
|
(1) The rate base and authorized rate of return presented in this table are the
rate base and rate of return from the last base rate case for each
jurisdiction. These rate bases and rates of return are not indicative of
current or future rate bases or rates of return.
(2) A rate base or rate of return were not included in the respective state
commission's final decision.
RECENT RATEMAKING ACTIVITY
Approximately 97 percent, 96 percent and 97 percent of our utility revenues
in the fiscal years ended September 30, 2003, 2002 and 2001 were derived from
sales at rates set by or subject to approval by local or state authorities. Net
annual rate increases totaling $18.6 million and $6.4 million became effective
in fiscal 2003 and fiscal 2001. There were no rate increases which became
effective in fiscal 2002.
11
The following table and discussion summarizes the major rate requests that
we have made and other ratemaking developments during the most recent five
fiscal years and the action taken on such requests.
AMOUNT
EFFECTIVE AMOUNT RECEIVED
JURISDICTION DATE REQUESTED (REDUCED)
------------ --------- --------- ----------
(IN THOUSANDS)
Kansas........................................ (a) $ 7,400 (a)
Colorado...................................... 05/04/01 4,200 $ 2,750
Kentucky...................................... 12/21/99 14,127 9,900
Louisiana:
Trans La System............................. 11/01/02 --(b) 364(c)
LGS System.................................. 11/01/02 --(b) 11,890(d)
Tennessee..................................... 04/1/99 --(b) (e)
Georgia....................................... 05/1/99 --(b) (e)
Iowa.......................................... 03/05/01 --(b) (326)
Illinois...................................... 10/23/00 3,100 1,367
Virginia...................................... 04/01/01 2,100 (534)
Texas:
West Texas System........................... 12/01/00 9,827 3,011
Amarillo System............................. 1/01/00 4,354 2,200
Amarillo System............................. 09/01/03 5,118 2,825
West Texas System........................... (f) 7,700 (f)
Lubbock System.............................. (g) 3,000 (g)
Mississippi................................... (h) (b) (h)
|
(a) The Kansas Corporation Commission is scheduled to conduct a public hearing
on this case in December 2003.
(b) No requested amounts are presented because either (1) we file periodic
requests for rate adjustments based upon our actual expenses in accordance
with the respective state commission's rules or (2) the commission's ruling
was not the result of a rate filing initiated by us. See further information
in the following discussion.
(c) In 2002, we submitted our 2001 rate stabilization filing and received tariff
revisions which resulted in an increase in annual revenues of $0.5 million
during the first 24-month period. Subsequent to the first 24-month period,
adjusted rates will provide an increase in annual revenues of $0.4 million.
(d) In 2002, we submitted our 2001 rate stabilization filing and received tariff
revisions which resulted in an increase in annual revenues of $15.3 million
during the first 24-month period. Subsequent to the first 24-month period,
adjusted rates will provide an increase in annual revenues of $11.9 million.
(e) Effective April 1, 1999, the Tennessee Regulatory Authority approved a
performance-based ratemaking mechanism related to gas procurement and gas
transportation activities. Effective May 1, 2002, the Georgia Public Service
Commission renewed our performance-based ratemaking program. The impacts of
these rulings are described in greater detail below.
(f) This case was filed in September 2003 and is pending review by the affected
cities.
(g) This case was filed in October 2003 and is pending review by the City of
Lubbock.
(h) In October 2003, the Mississippi Public Service Commission issued a final
ruling which denied our May 2003 request for a rate adjustment. We are
currently considering our response to the Commission's ruling.
12
Atmos Energy Colorado-Kansas Division. In May 2003, the Colorado-Kansas
Division filed a rate case with the Kansas Corporation Commission for
approximately $7.4 million in additional annual revenues. The Kansas Corporation
Commission is scheduled to conduct a public hearing on the case in December
2003. Additionally, in May 2003, we received approval for WNA in Kansas which
will be effective October through May of each year beginning with the 2003-2004
winter heating season.
In November 2000, the Colorado-Kansas Division filed a rate case with the
Colorado Public Utilities Commission for approximately $4.2 million in
additional annual revenues. In May 2001, we received an increase in annual
revenues of approximately $2.8 million from the Colorado Public Utilities
Commission. The new rates went into effect on May 4, 2001.
Atmos Energy Kentucky Division. On March 25, 2002, the Kentucky Commission
issued an Order approving a four year extension, effective April 1, 2002, of the
Performance-based Ratemaking mechanism related to gas procurement and gas
transportation activities filed by the Kentucky Division. The Performance-based
Ratemaking mechanism is incorporated into the Kentucky Division's gas cost
adjustment clause and provides for the sharing of purchased gas cost savings
between our customers and us. We recognized other income of $1.3 million, $1.1
million and $0.2 million under the Kentucky Performance-based-ratemaking
mechanism in fiscal years 2003, 2002 and 2001.
In May 1999, the Kentucky Division requested from the Kentucky Public
Service Commission a $14.1 million increase in revenues, a weather normalization
adjustment and changes in rate design to shift a portion of revenues from
commodity charges to fixed rates. In December 1999, the Kentucky Commission
granted an increase in annual revenues of approximately $9.9 million. The new
rates were effective for services rendered on or after December 21, 1999. In
addition, the Kentucky Commission approved a five-year pilot program for weather
normalization beginning in November 2000.
Atmos Energy Louisiana Division. In October 2002, Atmos received written
notification from the Executive Secretary of the Louisiana Public Service
Commission that he was asserting that a monthly facilities fee of approximately
$0.6 million charged since July 2001 to Atmos by Trans Louisiana Gas Pipeline,
Inc., a wholly-owned subsidiary of Atmos, pursuant to a contract between the
parties, was excessive. The Executive Secretary asserted that all monthly
facilities fees in excess of approximately $0.1 million from July 2001 should be
refunded to ratepayers with interest. In September 2003, an agreement was
reached with the commission staff to allow Atmos to charge a facilities fee of
approximately $0.5 million per month (subject to future escalation) beginning
November 1, 2003 for a period of 14 years. No retroactive adjustments will be
required under this agreement. On October 8, 2003, the commission unanimously
voted in open session to approve the agreement.
In January and February 2002, our Louisiana Division submitted its 2001
Rate Stabilization filings to the Louisiana Public Service Commission for the
two gas systems we operate in Louisiana. The Louisiana Public Service Commission
audited the filings and found our earnings to be deficient and that rate
adjustments were appropriate. Approved tariff revisions, which became effective
November 1, 2002, will result in $15.3 million in additional revenues per year
for our LGS System and $0.5 million for our Trans La System during the first
24-month period. Subsequent to the first 24-month period, adjusted rates will
provide total annual revenue increases of $11.9 million for our LGS System and
$0.4 million for our Trans La System. As a result of the actions taken by the
Louisiana Public Service Commission, we have decreased the overall weather
impact to our revenues in Louisiana.
In 2001, in connection with its review of our acquisition of Louisiana Gas
Service, the Louisiana Public Service Commission approved a rate structure that
requires us to share with the customers of Louisiana Gas Service cost savings
that resulted from the acquisition. The shared cost savings will be the
difference between operation and maintenance expense in any future year and the
1998 normalized expense for Louisiana Gas Service, indexed for inflation, annual
changes in labor costs and customer growth. Beginning January 1, 2002, customers
have been assured they will receive annual savings, which will be indexed for
inflation, annual changes in labor costs and customer growth. The sharing
mechanism will remain in place for 20 years subject to established modification
procedures.
13
In June 1999, our Trans La operations were involved in a rate investigation
before the Louisiana Public Service Commission, including the redesign of rates
to mitigate the effects of warm winter weather. A decision was rendered by the
Louisiana Commission in October 1999 that increased service charges associated
with customer service calls and increased the monthly customer charges from $6
to $9, both effective November 1, 1999. While these changes are revenue neutral,
they have mitigated the impact of warmer than normal winter weather on earnings.
The decision also included a three-year rate stabilization clause which will
allow the Trans La operations of our Louisiana Division's rates to be adjusted
annually to allow us to earn a return on equity within certain ranges that will
be monitored on an annual basis.
Atmos Energy Mid-States Division. Effective April 1, 1999, the Tennessee
Regulatory Authority approved the Mid-States Division's request to continue its
Performance-based Ratemaking mechanism related to gas procurement and gas
transportation activities. The Tennessee Regulatory Authority revised the
mechanism from the original two-year experimental period, by increasing the cap
for incentive gains and/or losses to $1.25 million per year. Under this
agreement, the mechanism has no expiration date and can be amended or cancelled
by either the Mid-States Division or the Tennessee Regulatory Authority
according to the provisions of the agreement. Similar to Tennessee, the Georgia
Public Service Commission renewed our Performance-based Ratemaking program for
an additional three years effective May 1, 2002. The gas purchase and capacity
release mechanisms of the Performance-based Ratemaking mechanism are designed to
provide us incentives to find innovative methods to lower gas costs to our
customers. We recognized other income of $0.5 million, $0.4 million and $1.0
million in fiscal years 2003, 2002 and 2001 attributable to the Georgia and
Tennessee Performance-based Ratemaking mechanisms.
In March 2001, the Mid-States Division and the Iowa Consumer Advocate
Division of the Department of Justice reached an agreement for an annual rate
reduction of $0.3 million relating to our Iowa operations. The rate reduction
was effective in March 2001. Also in 2001, the Mid-States Division filed
requests for accounting orders related to uncollectible delinquencies in three
states. As a result, we were able to defer $1.5 million as a regulatory asset.
In February 2000, the Mid-States Division filed a rate case in Illinois
with the Illinois Commerce Commission requesting an increase in annual revenues
of approximately $3.1 million. After review by the Illinois Commerce Commission,
we received an increase in annual revenues of approximately $1.4 million. The
new rates went into effect on October 23, 2000 and are collected primarily
through an increase in monthly customer charges.
In March 2000, the Mid-States Division filed a rate case in Virginia with
the State Corporation Commission of the Commonwealth of Virginia requesting an
increase in annual revenues of approximately $2.3 million. The State Corporation
Commission of Virginia reviewed the filing to determine if it met the
appropriate rules and regulations. In July 2000, we re-filed the case requesting
an increase in revenues of approximately $2.1 million. The Commission accepted
the revised filing. In April 2001, the Mid-States Division agreed to an annual
rate reduction of $0.5 million effective beginning with the April 2001 billing
cycle.
Atmos Energy Texas Division. In June 2003, the Texas Division filed a rate
case in Amarillo, Texas, requesting a $5.1 million increase in annual revenues.
In August 2003, the City of Amarillo, Texas approved an annual increase of
approximately $2.8 million, which was effective for bills rendered on or after
September 1, 2003. The increase was primarily comprised of an increase in
monthly customer charges. The agreement with Amarillo also provided for changes
in the rate structure to recover the cost of uncollectible accounts, adjustments
to base rates to compensate for declining gas use per customer and provided WNA,
which will be effective October through May, beginning in fiscal 2004.
In September 2003, the Texas Division filed a rate case in its West Texas
System to request a $7.7 million increase in annual revenues and WNA for our
residential, commercial and public-authority customers. The filing is pending
review by the affected cities. In October 2003, the Texas Division filed a rate
case in Lubbock to request a $3.0 million increase in annual revenues and WNA
for our residential, commercial and public-authority customers. The filing is
pending review by the City of Lubbock.
14
In August 1999, the Texas Division filed rate cases in its West Texas
System cities and Amarillo, Texas, requesting rate increases of approximately
$9.8 million and $4.4 million. The Texas Division received an increase in annual
revenues of approximately $2.1 million in base rates plus an increase of $0.1
million in service charges in Amarillo, Texas, effective for bills rendered on
or after January 1, 2000. The agreement with Amarillo also provided for changes
in the rate structure to reduce the impact of warmer than normal weather and to
improve the recovery of the actual cost of service calls. The Texas Division's
request for its West Texas System cities was initially denied, and in March 2000
this decision was appealed to the Railroad Commission of Texas (Railroad
Commission). Subsequently, 59 cities ratified a non-binding Settlement Agreement
which capped the rate increase at $3.0 million and entitled the ratifying cities
to accept a rate increase below $3.0 million in the event the Railroad
Commission adopted a lesser increase for the non-ratifying cities. The remaining
eight cities declined to participate in the settlement and a hearing with the
Railroad Commission was held in August 2000. In December 2000, the Railroad
Commission approved a settlement which increased annual revenues by
approximately $3.0 million that covered all 67 cities served by the West Texas
System effective December 1, 2000. In addition, the Railroad Commission approved
a new rate design providing more protection from warmer than normal weather for
our West Texas System.
Mississippi Valley Gas Company Division. The Mississippi Public Service
Commission requires that we file for rate adjustments based on our expenses
every six months. Typically, rate adjustments are filed in May and November of
each year and the rate becomes effective in June and December. In October 2003,
the Mississippi Public Commission issued a final order which denied our May 2003
request for a rate adjustment. We are currently considering our response to the
Commission's ruling. Additionally, we filed our second semi-annual filing on
November 5, 2003.
COMPETITION
Our utility operations are not currently in significant direct competition
with any other distributors of natural gas to residential and commercial
customers within our service areas. However, we do compete with other natural
gas suppliers and suppliers of alternative fuels for sales to industrial and
agricultural customers. We compete in all aspects of our business with
alternative energy sources, including, in particular, electricity. Competition
for residential and commercial customers is increasing. Promotional incentives,
improved equipment efficiencies and promotional rates all contribute to the
acceptability of electrical equipment. Electric utilities offer electricity as a
rival energy source and compete for the space heating, water heating and cooking
markets. The principal means to compete against alternative fuels is lower
prices, and natural gas historically has maintained its price advantage in the
residential, commercial and industrial markets. In addition, our Natural Gas
Marketing segment competes with other natural gas brokers in obtaining natural
gas supplies for customers.
EMPLOYEES
At September 30, 2003, we had 2,905 employees, consisting of 2,817
employees in our utility segment and 88 employees in our other segments. See
"Operating Statistics -- Utility Sales and Statistical Data by Division" for the
number of employees by division.
OTHER INFORMATION
We post our SEC filings on our website at www.atmosenergy.com.
CORPORATE GOVERNANCE
In accordance with relevant provisions of the Sarbanes-Oxley Act of 2002,
related releases of the Securities and Exchange Commission as well as corporate
governance listing standards of the New York Stock Exchange, the Board of
Directors of the Company has recently adopted the Company's Corporate Governance
Guidelines and revised the Company's Code of Conduct, which is now applicable to
all directors, officers and employees of the Company. In addition, the Board of
Directors has revised the charters for each of its Audit, Human Resources and
Nominating and Corporate Governance Committees. All of the foregoing documents
are posted on the Corporate Governance page of the Company's website.
15
ITEM 2. PROPERTIES
DISTRIBUTION, TRANSMISSION AND RELATED ASSETS
Our utility segment owns an aggregate of 45,267 miles of underground
distribution and transmission mains throughout our gas distribution systems.
These mains are located on easements or rights-of-way which generally provide
for perpetual use. We maintain our mains through a program of continuous
inspection and repair and believe that our system of mains is in good condition.
Our utility segment also holds franchises granted by the incorporated
cities and towns that we serve. At September 30, 2003, we held 651 franchises
having terms generally ranging from five to 25 years. We believe that each of
our franchises will be renewed.
STORAGE ASSETS
Our utility and other non-utility segments own underground gas storage
facilities in several states to supplement the supply of natural gas in periods
of peak demand. The following table summarizes key information regarding our
underground gas storage facilities:
MAXIMUM DAILY
USABLE CAPACITY CUSHION GAS TOTAL CAPACITY DELIVERY CAPABILITY
FACILITY LOCATION (MCF) (MCF)(1) (MCF) (MCF)
-------- -------- --------------- ----------- -------------- -------------------
Utility Segment
St. Charles................... Hopkins County, Ky 3,560,600 3,470,000 7,030,600 44,600
Goodwin....................... Monroe County, Ms 1,550,000 300,000 1,850,000 20,000
Amory......................... Monroe County, Ms 1,460,000 1,000,000 2,460,000 25,000
Bon Harbor.................... Daviess County, Ky 778,600 1,300,000 2,078,600 24,000
Hickory....................... Daviess County, Ky 451,600 850,000 1,301,600 24,000
Columbus LNG Plant............ Muscogee County, Ga 450,000 50,000 500,000 30,000
Grandview..................... Daviess County, Ky 305,400 350,000 655,400 4,500
Kirkwood...................... Hopkins County, Ky 221,900 400,000 621,900 12,000
---------- ---------- ---------- -------
Total Utility Segment....... 8,778,100 7,720,000 16,498,100 184,100
Other Non-Utility Segment
Liberty North................. Montgomery County, Ks 2,800,000 2,000,000 4,800,000 40,000
East Diamond.................. Hopkins County, Ky 2,160,000 1,640,000 3,800,000 40,000
Barnsley...................... Hopkins County, Ky 1,278,900 1,600,000 2,878,900 30,000
Liberty South................. Montgomery County, Ks 439,000 300,000 739,000 5,000
Napoleonville(2).............. Assumption Parish, La 438,583 300,973 739,556 56,000
Buffalo....................... Wilson County, Ks 200,000 180,000 380,000 5,000
Fredonia...................... Wilson County, Ks 200,000 160,000 360,000 5,000
Crofton....................... Christian County, Ky 54,000 55,000 109,000 1,000
---------- ---------- ---------- -------
Total Other Non-Utility
Segment................... 7,570,483 6,235,973 13,806,456 182,000
---------- ---------- ---------- -------
TOTAL......................... 16,348,583 13,955,973 30,304,556 366,100
========== ========== ========== =======
|
(1) Cushion gas represents the volume of gas that must be retained in a facility
to maintain reservoir pressure.
(2) We own 25 percent of this facility and Acadian Gas Pipeline System owns the
remaining 75 percent of this facility. Acadian Gas Pipeline System operates
this facility.
16
Additionally, we contract for storage service in underground storage
facilities on many of the interstate pipelines serving us to supplement our
proprietary storage capacity. The following table summarizes our contracted
storage capacity.
MAXIMUM
MAXIMUM DAILY
STORAGE WITHDRAWAL
QUANTITY QUANTITY
DIVISION/COMPANY CONTRACTOR (MMBTU) (MMBTU)(1)
---------------- ---------- ---------- ----------
Utility Segment
Colorado-Kansas Division....... Southern Star Central Pipeline 2,699,598 44,217
Tenaska Marketing Ventures 500,000 7,000
Public Service Company of Colorado 434,997 15,000
Colorado Interstate Gas Company 422,142 12,985
Kinder Morgan, Inc. 90,000 2,000
Centerpoint Energy Gas Transmission 28,500 950
Kentucky Division.............. Texas Gas Transmission 3,841,150 41,060
Tennessee Gas Pipeline Company 1,313,538 22,698
Louisiana Division............. Gulf South 1,941,280 97,064
Louisiana Intrastate Gas Company 600,000 60,000
Sonat 4,771 102
Tennessee Gas Pipeline Company 4,466 91
Mid-States Division............ Atmos Energy Marketing 2,173,543 19,634
Southern Natural Gas Company 1,423,374 28,741
Texas Eastern Transmission Company 1,253,969 19,636
Panhandle Eastern Pipeline 972,462 15,241
Tennessee Gas Pipeline Company 848,278 20,266
Gallagher Drilling Company(2) 640,000 5,000
ANR Pipeline Company 633,034 12,661
Dominion 609,008 8,136
Transco. 521,580 12,212
Virginia Gas 480,000 33,000
Egyptian Gas Storage Corp. 400,000 5,000
East Tennessee 339,900 36,547
Natural Gas Pipeline Company 312,750 5,580
Texas Gas Transmission 239,576 5,108
CMS Trunkline Gas Company 220,455 2,940
MRT Energy Marketing 137,493 2,395
Texas Division................. ONEOK Texas Gas Storage LLP 1,000,000 50,000
|
17
MAXIMUM
MAXIMUM DAILY
STORAGE WITHDRAWAL
QUANTITY QUANTITY
DIVISION/COMPANY CONTRACTOR (MMBTU) (MMBTU)(1)
---------------- ---------- ---------- ----------
Mississippi Valley Gas Company
Division..................... Gulf South 1,237,500 61,875
Southern Natural Gas 1,049,436 21,191
Texas Gas Transmission 1,023,039 45,139
Texas Eastern 518,220 8,637
Hattiesburg Gas Storage Company 400,000 40,000
Trunkline Gas Company 24,840 331
Tennessee Gas Pipeline Company 3,394 113
---------- -------
Total Utility Segment.......... 28,342,293 762,550
Natural Gas Marketing
Segment...................... Texas Gas Transmission 1,700,000 10,000
Atmos Energy Marketing, LLC.... Gulf South Pipeline Company(3) 1,250,000 100,000
TCO 1,197,000 25,000
East Tennessee 268,037 11,000
---------- -------
Total Natural Gas Marketing
Segment...................... 4,415,037 146,000
Other Non-utility Segment
Trans Louisiana Gas Pipeline,
Inc.......................... Bridgeline Gas Distribution LLC 300,000 30,000
---------- -------
Total Other Non-Utility
Segment...................... 300,000 30,000
---------- -------
TOTAL CONTRACTED STORAGE
CAPACITY..................... 33,057,330 938,550
========== =======
|
(1) Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending
upon the season and the month. Unless otherwise noted, MDWQ amounts
represent the MDWQ amounts as of November 1, which is the beginning of the
winter heating season.
(2) We contract for storage service in two underground storage facilities,
Wiseman and Ellis, from this company.
(3) Included in this amount is a contract signed in July 2003 for 1 Bcf in a
salt dome storage facility located in Louisiana with a total capacity of 5
Bcf. This facility provides increased flexibility because it allows us to
inject and withdraw gas on a daily and monthly basis. The contract commenced
in November 2003 and will last for 5 winter heating seasons.
OTHER FACILITIES
Our utility segment owns and operates one propane peak shaving plant with a
total capacity of approximately 180,000 gallons that can produce an equivalent
of approximately 3,300 Mcf daily.
OFFICES
Our administrative offices are consolidated in Dallas, Texas under one
lease. We also maintain field offices throughout our distribution system, the
majority of which are located in leased facilities. Our non-utility operations
are headquartered in Houston, Texas, with offices in Houston and other
locations, primarily in leased facilities.
18
ITEM 3. LEGAL PROCEEDINGS
See Note 13 to the consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of fiscal 2003.
19
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of September 30,
2003, regarding the executive officers of the Company. It is followed by a brief
description of the business experience of each executive officer.
YEARS OF
NAME AGE SERVICE OFFICE CURRENTLY HELD
---- --- -------- ---------------------
Robert W. Best................. 56 6 Chairman, President and Chief Executive
Officer
John P. Reddy.................. 50 5 Senior Vice President and Chief Financial
Officer
R. Earl Fischer................ 64 41 Senior Vice President, Utility Operations
JD Woodward III................ 53 2 Senior Vice President, Non-Utility
Operations
Louis P. Gregory............... 48 3 Senior Vice President and General Counsel
Wynn D. McGregor............... 50 15 Vice President, Human Resources
|
Robert W. Best was named Chairman of the Board, President and Chief
Executive Officer in March 1997. He previously served as Senior Vice
President -- Regulated Businesses of Consolidated Natural Gas Company (January
1996-March 1997) and was responsible for its transmission and distribution
companies.
John P. Reddy was named Senior Vice President and Chief Financial Officer
in September 2000. From April 2000 to September 2000, he was Senior Vice
President, Chief Financial Officer and Treasurer. Mr. Reddy previously served
the Company as Vice President, Corporate Development and Treasurer from December
1998 to March 2000. He joined the Company in August 1998 from Pacific
Enterprises, a Los Angeles, California based utility holding company whose
principal subsidiary was Southern California Gas Co. where he was Vice President
of Planning and Advisory Services responsible for corporate development and
merger and acquisition activities. Mr. Reddy was with Pacific Enterprises from
1980 to 1998 in various management and financial positions.
R. Earl Fischer was named Senior Vice President, Utility Operations in May
2000. He previously served the Company as President of the Texas Division from
January 1999 to April 2000 and as President of the Kentucky Division from
February 1989 to December 1998.
JD Woodward was named Senior Vice President, Non-Utility Operations in
April 2001. Prior to joining the Company, Mr. Woodward was President of Woodward
Marketing, L.L.C. from January 1995 to March 2001.
Louis P. Gregory joined the Company as Senior Vice President and General
Counsel in September 2000. Prior to joining the Company, he practiced law from
April 1999 to August 2000 with the law firm of McManemin & Smith. Prior to that,
he served as a consultant and independent contractor from August 1996 to
December 1998 for Nomas Corp. (formerly known as Lomas Mortgage USA, Inc.) and
Siena Holdings, Inc. (formerly known as Lomas Financial Corporation).
Wynn D. McGregor was named Vice President, Human Resources in January 1994.
He previously served the Company as Director of Human Resources from February
1991 to December 1993 and as Manager, Compensation and Employment from December
1987 to January 1991.
20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our 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 our common
stock for fiscal 2003 and 2002 are listed below. The high and low prices listed
are the closing NYSE quotes for shares of our common stock:
2003 2002
--------------------------- ---------------------------
DIVIDENDS DIVIDENDS
HIGH LOW PAID HIGH LOW PAID
------ ------ --------- ------ ------ ---------
QUARTER ENDED:
December 31.................. $23.63 $20.70 $ .30 $22.10 $19.46 $.295
March 31..................... 24.20 20.95 .30 24.20 20.26 .295
June 30...................... 25.45 21.43 .30 24.46 21.25 .295
September 30................. 25.07 23.20 .30 22.75 18.37 .295
----- -----
$1.20 $1.18
===== =====
|
Dividend payments are subject to restriction under the terms of our First
Mortgage Bond agreements. See Note 6 to the consolidated financial statements.
The number of record holders of our common stock on September 30, 2003 was
28,510.
The following table sets forth the number of securities authorized for
issuance under our equity compensation plans at September 30, 2003.
NUMBER OF
SECURITIES
NUMBER OF WEIGHTED- REMAINING AVAILABLE
SECURITIES TO BE AVERAGE EXERCISE FOR FUTURE ISSUANCE
ISSUED UPON PRICE OF UNDER EQUITY
EXERCISE OF OUTSTANDING COMPENSATION PLANS
OUTSTANDING OPTIONS, (EXCLUDING
OPTIONS, WARRANTS WARRANTS AND SECURITIES REFLECTED
AND RIGHTS RIGHTS IN COLUMN(A))
----------------- ---------------- --------------------
(A) (B) (C)
EQUITY COMPENSATION PLANS APPROVED BY
SECURITY HOLDERS:
Long-Term Incentive Plan........... 1,827,310 $21.91 1,923,464
Long-Term Stock Plan for the Mid-
States Division................. 6,300 $15.62 168,550
--------- ------ ---------
TOTAL EQUITY COMPENSATION PLANS
APPROVED BY SECURITY HOLDERS....... 1,833,610 $21.89 2,092,014
EQUITY COMPENSATION PLANS NOT
APPROVED BY SECURITY HOLDERS....... -- -- --
--------- ------ ---------
Total................................ 1,833,610 $21.89 2,092,014
========= ====== =========
|
21
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data of the Company and
should be read in conjunction with the consolidated financial statements
included herein.
YEAR ENDED SEPTEMBER 30
--------------------------------------------------------------
2003(1) 2002 2001(2) 2000(3) 1999
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS)
RESULTS OF OPERATIONS
Operating revenues......................... $2,799,916 $1,650,964 $1,725,481 $ 850,152 $ 690,196
Gross profit............................... 534,976 431,140 375,208 325,706 299,794
Operating expenses......................... 347,136 275,809 244,927 240,390 245,555
Operating income........................... 187,840 155,331 130,281 85,316 54,239
Other income (expense)..................... 2,191 (1,321) 6,188 14,744 10,123
Interest charges........................... 63,660 59,174 47,011 43,823 37,063
Income before income taxes and cumulative
effect of accounting change.............. 126,371 94,836 89,458 56,237 27,299
Cumulative effect of accounting change, net
income tax benefit....................... (7,773) -- -- -- --
Income tax expense......................... 46,910 35,180 33,368 20,319 9,555
Net income................................. 71,688 59,656 56,090 35,918 17,744
Weighted average diluted shares
outstanding.............................. 46,496 41,250 38,247 31,594 30,819
Diluted net income per share............... $ 1.54 $ 1.45 $ 1.47 $ 1.14 $ .58
Cash flows from operations................. 49,541 297,395 82,995 54,196 84,698
Cash dividends paid per share.............. $ 1.20 $ 1.18 $ 1.16 $ 1.14 $ 1.10
Total utility throughput (MMcf)............ 247,965 208,541 217,774 197,564 195,587
Total natural gas marketing sales volumes
(MMcf)................................... 225,961 204,027 55,469 -- --
FINANCIAL CONDITION
Net property, plant and equipment.......... $1,515,989 $1,300,320 $1,335,398 $ 982,346 $ 965,782
Working capital............................ 22,282 (133,116) (86,778) (181,890) (151,622)
Total assets............................... 2,518,508 1,981,385 2,036,180 1,348,758 1,230,537
Short-term debt, inclusive of current
maturities of long-term debt............. 127,940 167,771 221,942 267,613 186,152
Total capitalization
Shareholders' equity..................... 857,517 573,235 583,864 392,466 377,663
Long-term debt (excluding current
maturities)............................ 863,918 670,463 692,399 363,198 377,483
---------- ---------- ---------- ---------- ----------
1,721,435 1,243,698 1,276,263 755,664 755,146
Capital expenditures....................... 159,439 132,252 113,109 75,557 110,353
FINANCIAL RATIOS
Capitalization ratio(4).................... 46.4% 40.6% 39.0% 38.4% 40.1%
Return on average shareholders'
equity(5)................................ 9.9% 9.9% 10.4% 9.3% 4.7%
|
(1) Financial results for fiscal 2003 include the results of MVG from December
3, 2002, the date of acquisition.
(2) Financial results for fiscal 2001 include the results of Louisiana Gas
Service Company from July 1, 2001 and Woodward Marketing L.L.C. from April
1, 2001, the date of each acquisition, and the equity earnings from our 45
percent investment in Woodward Marketing L.L.C. for the period October 1,
2001 through March 31, 2002.
(3) Financial results for 2000 include a $5.8 million pre-tax gain on the
contribution of our propane assets to U.S. Propane, L.P.
(4) The capitalization ratio is calculated by dividing shareholders' equity by
the sum of total capitalization, current maturities of long-term debt and
short-term debt.
(5) The return on average shareholders' equity is calculated by dividing current
year net income by the average of shareholders' equity for the previous five
quarters.
22
The following table presents a condensed income statement by segment for
the year ended September 30, 2003.
FOR THE YEAR ENDED SEPTEMBER 30, 2003
--------------------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
Operating revenues from external
parties......................... $1,552,857 $1,234,447 $12,612 $ -- $2,799,916
Intersegment revenues............. 1,225 434,046 9,018 (444,289) --
---------- ---------- ------- --------- ----------
1,554,082 1,668,493 21,630 (444,289) 2,799,916
Purchased gas cost................ 1,062,679 1,644,328 1,540 (443,607) 2,264,940
---------- ---------- ------- --------- ----------
Gross profit................. 491,403 24,165 20,090 (682) 534,976
Depreciation and amortization..... 83,849 1,261 1,891 -- 87,001
Other operating expenses.......... 246,420 9,335 5,062 (682) 260,135
---------- ---------- ------- --------- ----------
Operating income.................. 161,134 13,569 13,137 -- 187,840
Miscellaneous income (expense).... (218) 1,855 5,004 (4,450) 2,191
Interest charges.................. 63,226 2,864 2,020 (4,450) 63,660
---------- ---------- ------- --------- ----------
Income before income taxes and
cumulative effect of accounting
change.......................... 97,690 12,560 16,121 -- 126,371
Income tax expense................ 35,553 5,757 5,600 -- 46,910
---------- ---------- ------- --------- ----------
Income before cumulative effect of
accounting change............... 62,137 6,803 10,521 -- 79,461
Cumulative effect of accounting
change, net of income tax
benefit......................... -- (7,773) -- -- (7,773)
---------- ---------- ------- --------- ----------
Net income (loss).......... $ 62,137 $ (970) $10,521 $ -- $ 71,688
========== ========== ======= ========= ==========
|
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
This section provides management's discussion of the financial condition,
cash flows and results of operations of Atmos Energy Corporation with specific
information on results of operations and liquidity and capital resources. It
includes management's interpretation of our financial results, the factors
affecting these results, the major factors expected to affect future operating
results and future investment and financing plans. This discussion should be
read in conjunction with the Company's consolidated financial statements and
notes thereto.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR UNDER THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
The statements contained in this Annual Report on Form 10-K may contain
"forward-looking statements" within the meaning of Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical fact
included in this Report are forward-looking statements made in good faith by the
Company and are intended to qualify for the safe harbor from liability
established by the Private Securities Litigation Reform Act of 1995. When used
in this Report, or any other of the Company's documents or oral presentations,
the words "anticipate," "expect," "estimate," "plans," "believes," "objective,"
"forecast," "goal" or similar words are intended to identify forward-looking
statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those
expressed or implied in the statements relating to the Company's strategy,
operations, markets, services, rates, recovery of costs, availability of gas
supply and other factors. These risks and uncertainties include the following:
adverse weather conditions such as warmer than normal weather in the Company's
utility service territories or colder than normal weather which could adversely
affect our natural gas marketing activities; regulatory trends and decisions,
including deregulation initiatives and the impact of rate proceedings before
various state regulatory commissions; market risks beyond our control affecting
our risk management activities including market liquidity, commodity price
volatility and counterparty creditworthiness; national, regional and local
economic conditions, limited access to financial markets; inflation and
increased gas costs, including their effect on commodity prices for natural gas;
increased competition; and other uncertainties, all of which are difficult to
predict and many of which are beyond the control of the Company. Accordingly,
while the Company believes these forward-looking statements to be reasonable,
there can be no assurance that they will approximate actual experience or that
the expectations derived from them will be realized. Further, the Company
undertakes no obligation to update or revise any of its forward-looking
statements whether as a result of new information, future events or otherwise.
FACTORS THAT MAY AFFECT OUR FUTURE PERFORMANCE
Our performance in the future will primarily depend on the results of our
utility and natural gas marketing operations. Several factors exist that could
influence Atmos' future financial performance, some of which are described
below. They should be considered in connection with evaluating forward-looking
statements contained in this report or otherwise made by or on behalf of us
since these factors could cause actual results and conditions to differ
materially from those projected in these forward-looking statements.
OUR OPERATIONS ARE WEATHER SENSITIVE.
Weather is one of the most significant factors influencing our performance.
Our natural gas utility sales volumes and related revenues are correlated with
heating requirements that result from cold winter weather. Our agricultural
sales volumes are associated with the rainfall levels during the growing season
in our west Texas irrigation market. However, weather normalized rates in effect
in several of our jurisdictions should mitigate the adverse effects of warmer
than normal weather on our utility operating results. Finally, sustained cold
weather could adversely affect our natural gas marketing operations as we may be
required to purchase gas at spot rates in a rising market to obtain sufficient
volumes to fulfill some customer contracts.
24
OUR OPERATIONS ARE SUBJECT TO REGULATION WHICH CAN DIRECTLY IMPACT OUR
OPERATIONS.
Our natural gas utility business is subject to various regulated returns on
its rate base in each of the 12 states in which we operate. We monitor the
allowed rates of return, our effectiveness in earning such rates and initiate
rate proceedings or operating changes as needed. In addition, in the normal
course of the regulatory environment, assets are placed in service and
historical test periods are established before rate cases can be filed. Once
rate cases are filed, regulatory bodies have the authority to suspend
implementation of the new rates while studying the cases. Because of this
process, we must temporarily suffer the negative financial effects of having
placed assets in service without the benefit of rate relief, which is commonly
referred to as "regulatory lag". In addition, our debt and equity financing
programs are also subject to approval by regulatory bodies in certain states,
which could limit our ability to take advantage of favorable short-term market
conditions.
Our business could also be affected by deregulation initiatives, including
the development of unbundling initiatives in the natural gas industry.
Unbundling is the separation of the provision and pricing of local distribution
gas services into discrete components. It typically focuses on the separation of
the distribution and gas supply components and the resulting opening of the
regulated components of sales services to alternative unregulated suppliers of
those services. Because of our enhanced technology and distribution system
infrastructures, we believe that we are now positively positioned as unbundling
evolves. Consequently, we expect there would be no significant adverse effect on
our business should unbundling or further deregulation of the natural gas
distribution service business occur.
Finally, contractual limitations could adversely affect our ability to
withdraw gas from storage, which could cause us to purchase gas at spot prices
in a rising market to obtain sufficient volumes to fulfill customer contracts.
We seek to minimize this risk by increasing our storage capacity and enhancing
the flexibility of our natural gas marketing contracts.
OUR OPERATIONS ARE EXPOSED TO MARKET RISKS THAT ARE BEYOND OUR CONTROL, WHICH
COULD RESULT IN FINANCIAL LOSSES.
Our risk management operations are subject to market risks beyond our
control including market liquidity, commodity price volatility and counterparty
creditworthiness. Market liquidity is affected by the number of trading partners
in the market. As a result of the recent severe downturn in the natural gas
marketing industry, the number of trading partners has been reduced, which could
adversely impact the market liquidity for this industry and adversely affect our
natural gas marketing operations.
Further, although we maintain a risk management control policy, we may not
be able to completely offset the price risk associated with volatile gas prices
or the risk in our gas trading activities which could lead to financial losses.
Physical trading also introduces price risk on any net open positions at the end
of each trading day, as well as a risk of loss resulting from intra-day
fluctuations of gas prices and the potential for daily price movements between
the time natural gas is purchased or sold for future delivery and the time the
related purchase or sale is hedged. Although we manage our business to maintain
no open positions, at times, limited net open positions related to our physical
storage may occur on a short term basis. Net open positions may result in an
adverse impact on our financial condition or results of operations if market
prices react in an unfavorable manner.
Our utility segment uses a combination of storage and financial hedges to
protect against volatility in gas prices and to help moderate the effects of
higher customer accounts receivable caused by potentially higher gas prices. Our
natural gas marketing segment manages margins and limits risk exposure on the
sale of natural gas inventory or the offsetting fixed-price purchase or sale
commitments for physical quantities of natural gas through the use of a variety
of financial derivatives.
We could realize financial losses on these activities as a result of
volatility in the market value of the underlying commodities or if a
counterparty fails to perform under a contract.
Finally, the use of financial instruments to conduct our hedging and market
risk activities subjects us to counterparty risk. Adverse changes in the
creditworthiness of our counterparties could limit the level of
25
trading activities with these parties and increase the risk that these parties
may not perform under a contract. We believe this risk is mitigated due to the
large number of counterparties used in our risk management activities.
NATIONAL, REGIONAL AND LOCAL ECONOMIC CONDITIONS HAVE A DIRECT IMPACT ON OUR
OPERATIONS.
Our operations will always be affected by the conditions and overall
strength of the national, regional and local economies, including interest
rates, changes in the capital markets and increases in the costs of our primary
commodity, natural gas. These factors impact the amount of residential,
industrial and commercial growth in our service territories. Additionally, these
factors could adversely impact our customer collections.
Further, AEM's operations are concentrated in the natural gas industry, and
its customers and suppliers may be subject to economic risks affecting that
industry. During 2003, AEM's credit risk increased due to higher natural gas
prices as compared with the prior year. However, we believe this risk is
mitigated because a larger percentage of our natural gas marketing business in
the current year is with municipal customers (who typically are more
creditworthy) as compared with the prior year.
THE EXECUTION OF OUR BUSINESS PLAN COULD BE AFFECTED BY AN INABILITY TO ACCESS
FINANCIAL MARKETS.
We rely upon access to both short term and longer term capital markets as a
source of liquidity to satisfy our liquidity requirements. Although we believe
we will maintain sufficient access to these financial markets, adverse changes
in the economy, the overall health of the industries in which we operate and
changes to our credit ratings could limit access to these markets and restrict
the execution of our business plan.
INFLATION AND INCREASED GAS COSTS COULD ADVERSELY IMPACT OUR CUSTOMER BASE AND
CUSTOMER COLLECTIONS AND INCREASE OUR LEVEL OF INDEBTEDNESS.
Inflation has caused increases in certain operating expenses, and has
required assets to be replaced at higher costs. We have a process in place to
continually review the adequacy of our utility gas rates in relation to the
increasing cost of providing service and the inherent regulatory lag in
adjusting those gas rates. Historically, we have been able to budget and control
operating expenses and investments within the amounts authorized to be collected
in rates and intend to continue to do so. The ability to control expenses is an
important factor that will influence future results.
The rapid increases in the price of purchased gas, which has occurred in
some prior years, causes us to experience a significant increase in short-term
debt because we must pay suppliers for gas when it is purchased, which can be
significantly in advance of when these costs may be recovered through the
collection of monthly customer bills for gas delivered. Increases in purchased
gas costs also slow our utility collection efforts as customers are more likely
to delay the payment of their gas bills, leading to higher than normal accounts
receivable. This situation also results in higher short-term debt levels and
increased bad debt expense. Should the price of purchased gas increase
significantly in the upcoming heating season, we would expect increases in our
short-term debt, accounts receivable and bad debt expense during fiscal 2004.
Finally, higher costs of natural gas in recent years have already caused
many of our utility customers to conserve in the use of our gas services and
could lead to even more customers utilizing such conservation methods.
OUR OPERATIONS ARE SUBJECT TO INCREASED COMPETITION.
We are facing increased competition from other energy suppliers as well as
electric companies and from energy marketing and trading companies. In the case
of industrial customers, such as manufacturing plants, and agricultural
customers, adverse economic conditions, including higher gas costs, could cause
these customers to use alternative sources of energy such as electricity or to
bypass our systems in favor of special competitive contracts with lower per-unit
costs.
26
HIGHLIGHTS
- On December 3, 2002, we completed the acquisition of Mississippi Valley
Gas Company (MVG), a privately held utility, for approximately $150.0
million, which consisted of approximately $74.7 million in cash and
3,386,287 unregistered shares of our common stock. In addition, we paid
approximately $70.9 million to repay outstanding debt of MVG. Our
Mississippi Valley Gas Company Division provides natural gas distribution
service to approximately 261,500 residential, industrial and other
customers located primarily in the northern and central regions of
Mississippi.
- In January 2003, as a result of the adoption of EITF 02-03 which
precludes mark-to-market accounting for our natural gas marketing segment
inventory and energy trading contracts that are not derivatives, we
recorded a one-time noncash charge for a cumulative effect adjustment of
$12.9 million ($7.8 million, net of income tax benefit) on the
consolidated statements of income.
- On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due
2013. The net proceeds were used to repay debt under a short-term
acquisition credit facility used to partially finance the MVG
acquisition, to repay $54.0 million in unsecured senior notes held by
institutional lenders, short-term debt under our commercial paper program
and to provide funds for general corporate purposes.
- On June 23, 2003, we completed a public offering of 4,000,000 shares of
our common stock, and we sold an additional 100,000 shares of our common
stock in July 2003 when our underwriters exercised their overallotment
option (collectively referred to as the 2003 Offering). The 2003 Offering
was priced at $25.31 per share and generated net proceeds of
approximately $99.2 million. The proceeds were used to partially fund our
pension plan, to repay short-term debt and to fund general corporate
purposes including the purchase of natural gas for storage.
- In June 2003, we contributed to the Atmos Energy Corporation Master
Retirement Trust for the benefit of the Atmos Energy Corporation Pension
Account Plan $48.6 million in cash and 1,169,700 shares of Atmos
restricted common stock with a value of $28.8 million. The cash
contribution was financed through a combination of cash on hand and a
portion of the net proceeds received from the 2003 Offering. As a result
of this contribution and improved investment returns on the assets used
to fund the pension plan, the $39.4 million minimum pension liability
recognized during fiscal 2002 was eliminated in fiscal 2003.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Preparation of
these financial statements requires us to make estimates and judgments that
affect the reported amounts of assets, liabilities, revenues and expenses and
the related disclosures of contingent assets and liabilities. We based our
estimates on historical experience and various other assumptions that we believe
to be reasonable under the circumstances. On an ongoing basis, we evaluate our
estimates, including those related to risk management and trading activities,
allowance for doubtful accounts, legal and environmental accruals, insurance
accruals, pension and postretirement obligations, deferred income taxes and the
valuation of goodwill, indefinite-lived intangible assets and other long-lived
assets. Our critical accounting policies are reviewed by the Audit Committee on
a quarterly basis. Actual results may differ from estimates.
Regulation -- Our utility operations are subject to regulation with respect
to rates, service, maintenance of accounting records and various other matters
by the respective regulatory authorities in the states in which we operate. Our
regulated utility operations are accounted for in accordance with Statement of
Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain
Types of Regulation. This statement requires cost-based, rate-regulated entities
that meet certain criteria to reflect the financial effects of the ratemaking
and accounting practices and policies of the various regulatory commissions in
their financial statements. We record regulatory assets for costs that have been
deferred for which future recovery through customer rates is considered
probable. Regulatory liabilities are recorded when it is probable that revenues
will be reduced for amounts that will be credited to customers through the
ratemaking process. As a result, certain
27
costs that would normally be expensed under accounting principles generally
accepted in the United States are permitted to be capitalized because they can
be recovered through rates. Further, regulation may impact the period in which
revenues or expenses are recognized. The amounts to be recovered or recognized
are based upon historical experience and our understanding of the regulations.
The impact of regulation on our utility operations may be affected by decisions
of the regulatory authorities or the issuance of new regulations.
Revenue recognition -- Sales of natural gas to our utility customers are
billed on a monthly cycle basis; however, the billing cycle periods for certain
classes of customers do not necessarily coincide with accounting periods used
for financial reporting purposes. We follow the revenue accrual method of
accounting for utility segment revenues whereby revenues applicable to gas
delivered to customers, but not yet billed under the cycle billing method, are
estimated and accrued and the related costs are charged to expense.
Energy trading contracts resulting in the delivery of a commodity where we
are the principal in the transaction are recorded as natural gas marketing sales
or purchases at the time of physical delivery. Realized gains and losses from
the settlement of financial instruments that do not result in physical delivery
related to our natural gas marketing energy trading contracts and unrealized
gains and losses from changes in the market value of open contracts are included
as a component of natural gas marketing revenues.
Allowance for Doubtful Accounts -- For the majority of our receivables, we
establish an allowance for doubtful accounts based on an aging of those
receivable balances. We apply percentages to each aging category based on our
collections experience. On certain other receivables where we are aware of a
specific customer's inability or reluctance to pay, we record an allowance for
doubtful accounts against amounts due to reduce the net receivable balance to
the amount we reasonably expect to collect. However, if circumstances change,
our estimate of the recoverability of accounts receivable could be different.
Circumstances which could affect our estimates include, but are not limited to,
customer credit issues, the level of natural gas prices and general economic
conditions.
Derivatives and Hedging Activities -- We use a combination of storage and
financial hedges to protect us and our natural gas utility customers against
unusually large winter period gas price increases. Further, AEM manages margins
and limits risk exposure on the sale of natural gas inventory or the offsetting
fixed-price purchase or sale commitments for physical quantities of natural gas
through the use of gas futures, including forwards, over-the-counter and
exchange-traded options and swap contracts with counterparties.
Our financial hedges are accounted for under the mark-to-market method
pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging
Activities. Changes in the valuation of assets and liabilities arising from risk
management activities primarily result from changes in the valuation of the
portfolio of contracts, maturity and settlement of contracts and newly
originated transactions. Market prices and models used to value these
transactions reflect our best estimates considering various factors including
closing exchange and over-the-counter quotations, time value and volatility
factors underlying the contracts. Values are adjusted to reflect the potential
impact of an orderly liquidation of our positions over a reasonable period of
time under present market conditions. Changes in market prices and other
assumptions used in these models directly affect our estimate of the fair value
of these transactions.
However, because the costs of financial instruments used in our utility
segment will ultimately be recovered through our rates, current period changes
in the assets and liabilities from these risk management activities are recorded
as a component of deferred gas costs in accordance with SFAS 71. Accordingly,
there is no earnings impact to our utility segment as a result of the use of
financial instruments. The changes in the assets and liabilities from risk
management activities are recognized in purchased gas cost in the income
statement when the related costs are recovered through our rates.
In the management of natural gas requirements for municipalities and other
local utilities, AEM sells physical natural gas to customers for future
delivery. Over-the-counter swap agreements require AEM to receive or make
payments based on the difference between a fixed price and the market price of
natural gas on the settlement date. Options held to manage price risk provide
the right, but not the obligation, to buy or sell energy commodities at a fixed
price. AEM links these financial derivatives to physical delivery of natural gas
28
and typically balances its derivative positions at the end of each trading day.
However, at any point in time, AEM may not have completely offset its risk on
these activities.
AEM's physical trading activities involve utilizing physical assets
(storage and transportation) to sell and deliver gas to customers or to take a
position in the market based on anticipated price movement. In addition to the
price risk of any net open position at the end of each trading day, the
financial exposure that results from intra-day fluctuations of gas prices and
the potential for daily price movements constitutes a risk of loss since the
price of natural gas purchased or sold for future delivery at the beginning of
the day may not be hedged until later in the day.
Impairment Assessments -- We perform impairment assessments of our
goodwill, intangible assets subject to amortization and long-lived assets. We
currently have no indefinite-lived intangible assets. We annually evaluate our
goodwill balances for impairment during our second fiscal quarter or as
impairment indicators arise. We use a present value technique based on
discounted cash flows to estimate the fair value of our reporting units. Our
reporting units and our operating segments are the same as each operating unit
represents a component of our business. Goodwill is allocated to the reporting
units responsible for the acquisition that gave rise to the goodwill.
The discounted cash flow calculations used to assess goodwill impairment
are dependent on several subjective factors including the timing of future cash
flows, future growth rates, and the discount rate. An impairment charge is
recognized if the carrying value of a reporting unit's goodwill exceeds its fair
value.
We periodically evaluate whether events or circumstances have occurred that
indicate that our intangible assets subject to amortization and other long-lived
assets may not be recoverable or that the remaining useful life may warrant
revision. When such events or circumstances are present, we assess the
recoverability of these assets by determining whether the carrying value will be
recovered through expected future cash flows. These cash flow projections
consider various factors such as the timing of the future cash flows and the
discount rate and are based upon the best information available at the time the
estimate is made. Changes in these factors could materially affect the cash flow
projections and result in the recognition of an impairment charge. An impairment
charge is recognized as the difference between the carrying amount and the fair
value if the sum of the undiscounted cash flows is less than the carrying value
of the related asset.
Pension and Other Postretirement Plans -- Pension and other postretirement
plan expenses and liabilities are determined on an actuarial basis and are
affected by the market value of plan assets, estimates of the expected return on
plan assets and assumed discount rates and demographic data. The assumed return
on plan assets is based on management's expectation of the long-term return on
the portfolio of plan assets. The discount rate used to compute the present
value of plan liabilities generally is based on rates of high grade corporate
bonds with maturities similar to the average period over which benefits will be
paid. Actual changes in the fair market value of plan assets and differences
between the actual return on plan assets and the expected return on plan assets
could have a material effect on the amount of pension expense ultimately
recognized.
RESULTS OF OPERATIONS
The primary factors that impact our results of utility operations are
seasonal weather patterns, competitive factors in the energy industry and
economic conditions in our service areas. Natural gas sales to residential,
commercial and public authority customers are affected by winter heating season
requirements. This generally results in higher operating revenues and net income
during the period from October through March of each year and lower operating
revenues and either lower net income or net losses during the period from April
through September of each year. Accordingly, our second fiscal quarter
historically has been our most critical earnings quarter with an average of 68
percent of our net income having been earned in the second quarter during the
three most recently completed fiscal years. Utility sales to industrial
customers are much less weather sensitive. Utility sales to agricultural
customers, who typically use natural gas to power irrigation pumps during the
period from March through September, are primarily affected by rainfall amounts
and the price of natural gas. Changes in the cost of gas impact revenue but do
not directly affect our gross profit from utility operations because the
fluctuations in gas prices are passed through to the customer.
29
Our natural gas marketing segment generates income from its industrial,
utility and municipal customers through negotiated prices based on the volume of
gas supplied to the customer. It also generates income by utilizing storage and
transportation capacity that it controls to take advantage of the difference
between near-term gas prices and prices for future delivery as well as the daily
movement of gas prices.
The following table presents our financial highlights for the three fiscal
years ended September 30, 2003:
FOR THE YEAR ENDED SEPTEMBER 30
---------------------------------------
2003 2002 2001
----------- ----------- -----------
(IN THOUSANDS, UNLESS OTHERWISE NOTED)
Operating revenues............................... $2,799,916 $1,650,964 $1,725,481
Gross profit..................................... 534,976 431,140 375,208
Operating expenses............................... 347,136 275,809 244,927
Operating income................................. 187,840 155,531 130,281
Other income (expense)........................... 2,191 (1,321) 6,188
Interest charges................................. 63,660 59,174 47,011
Income before income taxes and cumulative effect
of accounting change........................... 126,371 94,836 89,458
Cumulative effect of accounting change, net of
income tax benefit............................. (7,773) -- --
Income tax expense............................... 46,910 35,180 33,368
Net income....................................... $ 71,688 $ 59,656 $ 56,090
Utility sales volumes -- MMcf.................... 184,512 145,488 156,544
Utility transportation volumes -- MMcf........... 63,453 63,053 61,230
---------- ---------- ----------
Total utility throughput -- MMcf............... 247,965 208,541 217,774
========== ========== ==========
Natural gas marketing sales volumes -- MMcf...... 225,961 204,027 55,469
========== ========== ==========
Heating Degree Days
Actual (weighted average)...................... 3,473 3,368 4,124
Percent of normal.............................. 101% 94% 115%
Consolidated utility average sales price per
Mcf............................................ $ 8.13 $ 6.11 $ 8.55
Consolidated utility average transportation
revenue per Mcf................................ $ 0.47 $ 0.58 $ 0.47
Consolidated utility average cost of gas per Mcf
sold........................................... $ 5.71 $ 3.78 $ 6.47
|
30
The following table reconciles the gross profit and throughput information
from a segment basis, before intercompany eliminations, to a consolidated basis:
FOR THE YEAR ENDED SEPTEMBER 30
---------------------------------------
2003 2002 2001
----------- ----------- -----------
(IN THOUSANDS, UNLESS OTHERWISE NOTED)
Utility segment gross profit......................... $491,403 $377,635 $362,785
Intersegment activity................................ 7,729 8,746 2,679
-------- -------- --------
Utility segment contribution to consolidated gross
profit............................................. $499,132 $386,381 $365,464
======== ======== ========
Natural gas marketing segment gross profit........... $ 24,165 $ 37, |