(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
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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)
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common stock, No Par Value New York Stock Exchange |
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.
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.
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.
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
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:
(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.
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
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
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.
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.
See footnotes following these tables.
See footnotes following these tables.
See footnotes following these tables.
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.
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
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.
(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.
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.
(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.
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.
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.
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.
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.
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:
(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.
(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.
See Note 13 to the consolidated financial statements.
No matters were submitted to a vote of security holders during the fourth
quarter of fiscal 2003.
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.
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.
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:
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.
The following table sets forth selected financial data of the Company and
should be read in conjunction with the consolidated financial statements
included herein.
(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.
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.
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:
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.
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.
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 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
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.
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 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.
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.
- 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
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
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.
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.
The following table presents our financial highlights for the three fiscal
years ended September 30, 2003:
YEAR ENDED SEPTEMBER 30, 2003 COMPARED WITH YEAR ENDED SEPTEMBER 30, 2002
Utility segment
Gross profit for our utility segment primarily consists of gas service
margins generated by our six utility operating divisions from the sale of
natural gas to approximately 1.7 million residential, commercial, industrial,
agricultural and other customers in the 12 states that comprise our utility
service areas.
Utility gross profit increased to $499.1 million for the year ended
September 30, 2003 from $386.4 million for the year ended September 30, 2002.
Total throughput for our utility business was 248.0 billion cubic feet (Bcf)
during the current year compared to 208.5 Bcf in the prior year. The increase in
utility gross profit and total throughput was primarily attributable to the
impact of the MVG acquisition in December 2002, which increased utility gross
profit and total throughput by $73.2 million and 32.6 Bcf. The increase in
utility gross profit was also attributable to a $13.3 million increase in our
base charges primarily in Louisiana as a result of our annual rate stabilization
clause filing which became effective in November 2002. These increases were
partially offset by a $3.9 million decrease in revenues from the impact of WNA
as a result of weather in our WNA service areas being 1 percent colder than
normal for the year ended September 30, 2003.
The average cost of gas per Mcf sold increased 51 percent to $5.71 for 2003
from $3.78 for 2002, resulting in a 33 percent increase in average sales price.
However, changes in the cost of gas do not directly affect utility gross profit
because the fluctuations in gas prices are passed through to the customer.
Gross profit for our natural gas marketing segment consists primarily of
the difference between revenue arising from the sale of physical natural gas to
our natural gas marketing customers less the cost to purchase natural gas and
unrealized gains and losses from changes in the market value of open contracts.
Our natural gas marketing gross profit was $24.8 million for the year ended
September 30, 2003 compared to gross profit of $38.4 million for the year ended
September 30, 2002. Natural gas marketing sales volumes were 226.0 Bcf during
the current year compared to 204.0 Bcf for the prior year. Our natural gas
marketing gross profit included an unrealized gain on open contracts of $6.3
million compared with an unrealized loss on open contracts of $10.5 million last
year.
Natural gas marketing gross profit for the year ended September 30, 2003
decreased as we purchased gas during a period of rising prices to meet our
contractual requirements with our customers due to several factors. We
anticipated a decline in natural gas prices during the period December 2002
through March 2003; therefore, we elected to keep gas in storage and to buy
flowing gas to meet our customer needs during that period. We were also unable
to withdraw planned volumes from storage to meet our non-utility customer needs
due to contractual and regulatory limitations relating to our storage
facilities. Additionally, we experienced situations of open short positions and
were not sufficiently hedged on other transactions, which contributed to the
decrease in our natural gas marketing gross profit. Finally, we recognized
smaller gains from inventory sales in the current year as compared with the
prior year.
Since the 2002-2003 winter heating season, we have taken steps to minimize
any future negative impact of the events that caused the lower-than-expected
earnings from our natural gas marketing segment during the year. In July 2003,
we entered into a contract for one Bcf of capacity in a salt dome storage
facility that will help us to manage our price risk related to customer demand
volatility. This facility provides increased flexibility to satisfy changing
customer demands because it allows us to inject and withdraw gas on a daily and
monthly basis. The contract commenced in November 2003 and will remain in effect
for the next five heating seasons. Annual lease payments will be approximately
$2.0 million. Additionally, we are amending our contracts with third parties,
where possible, to transfer usage risk to our customers and to provide higher
margins. Finally, we are reviewing our internal processes to improve the
effectiveness of our overall risk management and financial reporting processes.
Other Non-utility segment
Our other non-utility segment gross profit primarily consists of margins
generated by our third party storage services and our leasing operations. Our
other non-utility segment contributed $11.1 million in gross profit during the
current year compared with $6.4 million for the prior year. The increase in our
non-utility gross profit was primarily attributable to increased asset
management activities in the current year and an increase in leasing income
attributable to the commencement in 2003 of a new lease for a distributed
electric generation plant.
Operating expenses -- Operating expenses, which include operation and
maintenance expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes, increased 26 percent to
$347.1 million for the year ended September 30, 2003 from $275.8 million for the
year ended September 30, 2002. Operation and maintenance expense increased
primarily due to the addition of $36.0 million related to the MVG acquisition in
December 2002 and a $13.3 million increase in the provision for doubtful
accounts as a result of higher revenues and gas prices. This increase was
partially offset by a $3.2 million reduction in labor costs attributable to
lower incentive payment accruals as compared with the prior year. Taxes other
than income taxes increased $18.8 million primarily due to additional franchise,
payroll and property taxes associated with the MVG assets acquired in December
2002. Note that franchise and state gross receipts taxes are paid by our
customers; thus, these amounts are offset in revenues through customer billings
and have no effect on net income.
Interest charges -- Interest charges increased eight percent for the year
ended September 30, 2003 to $63.7 million from $59.2 million for the year ended
September 30, 2002. The increase was primarily attributable to a higher average
outstanding debt balance resulting from the financing obtained to fund the
acquisition of MVG.
Cumulative effect of change in accounting principle -- On January 1, 2003,
we recorded a cumulative effect of a change in accounting principle to reflect a
change in the way we account for our storage and transportation contracts.
Previously we accounted for those contracts under EITF 98-10, Accounting for
Energy Trading and Risk Management Activities, which required us to record
estimated future gains on our storage and transportation contracts at the time
we entered into the contracts and to mark those contracts to market value each
month. Effective January 1, 2003, we no longer mark those contracts to market.
As a result, we expensed $7.8 million, net of applicable income tax benefit, as
a cumulative effect of a change in accounting principle.
YEAR ENDED SEPTEMBER 30, 2002 COMPARED WITH YEAR ENDED SEPTEMBER 30, 2001
Utility segment
Gross profit for our utility segment increased six percent to $386.4
million for the year ended September 30, 2002 from $365.5 million for the year
ended September 30, 2001. Total throughput for 2002, excluding Louisiana Gas
Service Company's throughput, was 191.4 Bcf compared with 217.8 Bcf for 2001.
The increase in utility gross profit was due primarily to the gross profit
earned from additional throughput of 17.1 Bcf from the Louisiana Gas Service
operations acquired in July 2001. This increase was offset by the effect of
warmer weather, which resulted in a 12 percent decrease in gas sales volumes
excluding Louisiana Gas Service's gas sales volumes. During 2002, temperatures
were 18 percent warmer than the prior year and were six percent warmer than the
30-year normal, adjusted for service areas with weather normalized operations.
The average cost of gas per Mcf sold decreased 42 percent to $3.78 for 2002
from $6.47 for 2001, resulting in a 29 percent decrease in average sales price.
However, changes in the cost of gas do not directly affect gross profit because
the fluctuations in gas prices are passed through to the customer.
Natural gas marketing segment
Gross profit for our natural gas marketing segment was $38.4 million for
the year ended September 30, 2002 compared to gross profit of $2.2 million for
the year ended September 30, 2001. Natural gas marketing sales volumes were
204.0 Bcf during the current year compared to 55.5 Bcf for the prior year. The
increase for 2002 compared to 2001 was primarily due to gains on inventory sales
and favorable pricing under natural gas sales contracts as well as our full
consolidation of Woodward Marketing L.L.C. beginning April 2001 when we
completed our acquisition of the remaining 55 percent interest in Woodward
Marketing, L.L.C. that we did not already own. Since the acquisition, the
revenues and expenses of Woodward Marketing L.L.C. have been shown on a
consolidated basis.
Other Non-utility segment
Our other non-utility segment contributed $6.4 million in gross profit
during the current year compared with $7.6 million for the prior year.
Operating Expenses -- Operating expenses increased to $275.8 million for
the year ended September 30, 2002 from $244.9 million for the year ended
September 30, 2001. Operation and maintenance expense increased primarily due to
the addition of $21.5 million relating to the Louisiana Gas Service acquisition
in July 2001 and an increase of $10.7 million in pension costs. In addition,
operation and maintenance expense increased $9.2 million due to the full
consolidation of Woodward Marketing's operations beginning April 1, 2001. A
decrease in the provision for doubtful accounts of $26.2 million partially
offset this increase. The decrease in the provision for doubtful accounts was
attributable to the lower gas commodity prices during 2002 as well as our
effective recovery of customer receivable balances. Depreciation and
amortization increased $13.8 million due to the addition of the assets from the
Louisiana Gas Service acquisition in July 2001. Taxes other than income
decreased as a result of decreased city franchise taxes and state gross receipts
taxes, which are revenue based. However, these taxes are paid by our customers;
thus, these amounts are offset in revenues through customer billings and have no
effect on net income. The decrease in taxes other than income was partially
offset by increases in property and payroll taxes related to the Louisiana Gas
Service acquisition in July 2001.
Miscellaneous expense -- Miscellaneous expense decreased $0.6 million to
$1.3 million in 2002 compared to $1.9 million in 2001. This decrease was
primarily due to an increase in net recoveries related to our performance
based-ratemaking mechanisms, the recognition of $0.5 million related to a large
industrial contract we received during 2002 and a reduction in the amortization
expense recognized related to weather insurance purchased for the 2001-2002
heating season. In addition, we had an increase of $3.0 million in interest
income in May 2001 due primarily to interest income earned on the proceeds from
our $350.0 million debt offering in 2001. We invested these proceeds in
short-term investments until the completion of the Louisiana Gas Service
acquisition in July 2001. No such interest income was recognized in 2002.
Interest expense -- Interest expense increased $12.2 million to $59.2
million for 2002 compared to $47.0 million for 2001. This increase was due
primarily to the interest expense on the $350.0 million debt offering in May
2001.
Our working capital and liquidity for capital expenditures and other cash
needs are provided from internally generated funds, borrowings under our credit
facilities and commercial paper program and funds raised from the public debt
and equity capital markets. We believe that these sources of funds will provide
the necessary working capital and liquidity for capital expenditures and other
cash needs for fiscal 2004.
The following presents our capitalization as of September 30, 2003 and
2002:
Total debt as a percentage of total capitalization, including short-term
debt, was 53.6 percent and 59.4 percent at September 30, 2003 and 2002. The
improvement in the debt to capitalization ratio was primarily attributable to
the issuance of common stock in connection with our 2003 Offering and the MVG
acquisition as well as the elimination of the minimum pension liability as of
September 30, 2003 due to increased funding of our pension plan and improved
investment returns on the assets used to fund the pension plan. Our long-term
plan is to maintain the debt to capitalization ratio within a target range of
50-52 percent through cash flow generated from operations, continued issuance of
new common stock under our Direct Stock Purchase Plan and Retirement Savings
Plan, access to the debt and equity capital markets and limiting annual
maintenance and capital expenditures.
Our internally generated funds may change in the future due to a number of
factors, some of which we cannot control. These include regulatory changes, the
price for our products and services, the demand for such products and services,
margin requirements resulting from significant changes in commodity prices,
operational risks and other factors.
For the year ended September 30, 2003, we generated operating cash flow of
$49.5 million compared with $297.4 million in fiscal 2002 and $83.0 million in
fiscal 2001. The significant factors impacting our operating cash flow for the
last three fiscal years are summarized below.
Fiscal 2003 operating cash flow was adversely impacted by a $60.0 million
increase in accounts receivable due to higher revenues and the timing of
customer account collections. The increase in revenues is attributable to a 19
percent increase in consolidated utility throughput as a result of the impact of
our MVG acquisition and a 33 percent increase in average utility sales price per
Mcf primarily due to an increase in natural gas costs. Operating cash flow was
also adversely impacted by a significant increase in natural gas prices. These
increases resulted in a $64.9 million increase in gas stored underground and a
$24.2 million increase in deferred gas costs. Finally, operating cash flow
reflects the impact of the funding of our pension plan in June 2003, which
included a $48.6 million cash payment. This funding is discussed under the
caption Pension and Postretirement Benefits Obligations below.
In fiscal 2002, operating cash flow was favorably impacted by a $56.5
million reduction in cash held on deposit in margin accounts. This account
represents deposits recorded to collateralize certain of our financial
derivatives purchased in support of our natural gas marketing activities and
will fluctuate based upon the timing of our derivative activities. Operating
cash flow was also favorably impacted by a $52.3 million increase in accounts
payable and accrued liabilities and a $34.2 million increase in other current
liabilities primarily attributable to the timing of payments as compared with
the prior year. Finally, operating cash flow was favorably impacted by a $32.9
million decrease in deferred gas costs reflecting the favorable timing between
the billing of gas costs to our customers and the purchase of natural gas.
These favorable impacts were partially offset by a $12.2 million increase
in accounts receivable. This increase was attributable to revenue increases
resulting from the inclusion of the LGS and Woodward Marketing operations for a
full year and the timing of customer account collections.
In fiscal 2001, operating cash flow was favorably impacted by a $65.0
million decrease in accounts receivable attributable to improved customer
collections during fiscal 2001 and a $15.4 million decrease in deferred gas
costs reflecting the favorable timing between the billing of gas costs to our
customers and the purchase of natural gas.
These favorable impacts were partially offset by the $62.2 million deposit
of cash into margin accounts to collateralize certain of our financial
derivatives and a $94.8 million decrease in accounts payable and accrued
liabilities attributable to the timing of payments as compared with the prior
year.
During the last three years, a substantial portion of our cash resources
was used to fund acquisitions, our ongoing construction program to provide
natural gas services to our customer base and technology improvements.
Capital expenditures for 2004 are expected to approximate $175.0 million.
These expenditures include additional mains, services, meters and equipment.
Our cash flows used for investing activities for fiscal 2003 included $74.7
million for the cash portion of the Mississippi Valley Gas Company acquisition
completed in December 2002. Cash flows used for investing activities for fiscal
2002 included $15.7 million for the acquisition of Kentucky-based market area
storage and associated pipeline facility assets, certain natural gas purchase
and sales contracts and the outstanding common stock of Southern Resources, Inc.
Cash flows used for investing activities for fiscal 2001 included $363.4 million
for the acquisition of the assets of Louisiana Gas Service Company. In addition,
we received $8.6 million in cash during fiscal 2001 in connection with the
acquisition of the remaining 55 percent interest in Woodward Marketing that we
did not already own.
For the year ended September 30, 2003 our financing activities provided
$151.6 million of cash. Fiscal 2002 cash flows from financing activities
represented a use of cash of $106.4 million and, in fiscal 2001, our financing
activities provided $393.0 million of cash. Our significant financing activities
for the three years ended September 30, 2003 are summarized as follows:
- During fiscal 2003, we received $147.0 million from a short-term
acquisition credit facility which was used primarily to fund the $74.7
million cash portion of the purchase price for MVG in December 2002 and
to repay $70.9 million of MVG's outstanding debt.
- On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due
2013. The net proceeds of $249.3 million were used to refinance the
short-term acquisition credit facility of $147.0 million, to repay $54.0
million in unsecured senior notes held by institutional lenders, and
short-term debt under our commercial paper program and to provide funds
for general corporate purposes. In fiscal 2001, we issued $350.0 million
of 7.375% Senior Notes due in 2011 and received net proceeds of $347.1
million. The net proceeds were used to finance the acquisition of the
assets of Louisiana Gas Service Company.
- In June and July 2003, we sold a total of 4,100,000 shares of our common
stock in a public offering. The offering was priced at $25.31 per share
and generated net proceeds of $99.2 million. The net proceeds were used
to finance a portion of our pension plan contribution, repay short-term
debt and to provide for general corporate purposes. In fiscal 2001, we
issued 6,741,500 shares, which provided net proceeds of $142.0 million.
The net proceeds were used to repay commercial paper and to provide funds
for general corporate purposes.
- During fiscal 2003, 2002 and 2001, total short-term debt decreased by
$27.2 million, $55.5 million and $48.8 million.
- We repaid $73.2 million of long-term debt during fiscal 2003, which
includes the $54.0 million repayment of unsecured senior notes with the
proceeds received from our January 2003 debt offering. Fiscal 2002 and
2001 payments were $20.7 million and $17.7 million.
During the year ended September 30, 2003, we issued 9,799,853 shares of
common stock. Of these shares, 3,386,287 shares were issued in December 2002 for
the stock portion of the MVG acquisition, 4,100,000 shares were issued in
connection with our 2003 Offering and 1,169,700 shares were issued in connection
with our stock contribution to our pension plan in June 2003. The following
table shows the number of shares issued for the years ended September 30, 2003,
2002 and 2001:
SHELF REGISTRATION
In December 2001, we filed a shelf registration statement with the
Securities and Exchange Commission (SEC) to issue, from time to time, up to
$600.0 million in new common stock and/or debt. The registration statement was
declared effective by the SEC on January 30, 2002. As discussed above, on
January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013 under
the registration statement. The net proceeds of $249.3 million were used to
repay debt under an acquisition credit facility used to finance our acquisition
of MVG, to repay $54.0 million in unsecured senior notes held by institutional
lenders and short-term debt under our commercial paper program and to provide
funds for general corporate purposes. Additionally, as noted above, we sold
4,100,000 shares of our common stock in connection with our 2003 Offering under
the registration statement. After the debt offering and these common stock
sales, approximately $246.0 million remains available under the shelf
registration statement.
CREDIT FACILITIES
We maintain both committed and uncommitted credit facilities. Our credit
capacity and the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term borrowing
requirements, which are typically highest during colder months. Our working
capital needs can vary significantly due to changes in the price of natural gas
charged by suppliers and the increased gas supplies required to meet customers'
needs during periods of cold weather.
We have two short-term committed credit facilities totaling $368.0 million.
The first short-term unsecured credit facility is for $350.0 million, bears
interest at the Eurodollar rate plus 0.625 percent and
On October 7, 2002, we entered into a $150.0 million short-term unsecured
committed credit facility. This credit facility was used to provide initial
funding for the cash portion of the MVG acquisition and to repay MVG's existing
debt. A total of $147.0 million was borrowed under this credit facility during
the first quarter. This amount was refinanced in January 2003 with a portion of
the proceeds of our $250.0 million debt offering, as discussed above.
The availability of funds under our credit facilities is subject to
conditions specified therein, which we currently meet. These conditions include
our compliance with financial covenants and the continued accuracy of
representations and warranties contained in these agreements. We are required by
the financial covenants in our $350.0 million credit facility to maintain a
ratio of total debt to total capitalization of no greater than 70 percent. At
September 30, 2003, our total debt to total capitalization ratio, as defined,
was 55 percent.
Our Woodward Marketing subsidiary has a $210.0 million uncommitted demand
working capital credit facility that bears interest at LIBOR plus 2.5 percent.
Atmos Energy Holdings, Inc. (AEH) and Atmos Energy Marketing, LLC, our
wholly-owned subsidiaries, are guarantors of all amounts outstanding under this
facility. Effective October 1, 2003 with the reorganization of our natural gas
marketing segment, AEM became the borrower under the credit facility and AEH
became the sole guarantor of the facility. At September 30, 2003, no amount was
outstanding under this credit facility, although Woodward Marketing, L.L.C.
letters of credit totaling $76.9 million reduced the amount available. The
amount available under this credit facility is also limited by various
covenants, including covenants based on working capital. Under the most
restrictive covenant, the amount available to Woodward Marketing under this
credit facility at September 30, 2003 was $28.3 million. This credit facility
expires on March 31, 2004 and is expected to be renewed at that time.
We also have an unsecured short-term uncommitted credit line for $20.0
million. There were no borrowings under this uncommitted credit facility at
September 30, 2003. This uncommitted line is renewed or renegotiated at least
annually with varying terms and we pay no fee for the availability of the line.
Borrowings under this line are made on a when and as-available basis at the
discretion of the bank. This facility is also used for working capital purposes.
In October 2003, we increased the amount of this credit line to $25.0 million.
In addition, Woodward Marketing has a $100.0 million intercompany credit
facility with AEH for its non-utility business which bore interest at LIBOR plus
CREDIT RATING
Our credit ratings directly affect our ability to obtain short-term and
long-term financing, in addition to the cost of such financing. In determining
our credit ratings, the rating agencies consider a number of quantitative
factors, including debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and pension
liabilities and funding status. In addition, the rating agencies consider
qualitative factors such as consistency of our earnings over time, the quality
of our management and business strategy, the risk associated with our utility
and non-utility businesses and the regulatory structures that govern our rates
in the states where we operate.
Our credit ratings may be revised or withdrawn at any time by the rating
agencies, and each rating should be evaluated independently of any other rating.
There can be no assurance that a rating will remain in effect for any given
period of time or that a rating will not be lowered, or withdrawn entirely, by a
rating agency if, in its judgment, circumstances so warrant.
On January 10, 2003, S&P changed the outlook on our long-term debt rating
from "stable" to "negative." In its press release explaining this action, S&P
cited, among other factors, their concern that we have not made significant
progress in reducing our debt to total capitalization ratio. Since S&P changed
its outlook, we have issued equity and substantially reduced our leverage.
Moody's and Fitch each continue to maintain a "stable" outlook for our ratings.
We have no trigger events in our debt instruments that are tied to changes
in specified credit ratings or stock price, nor have we entered into any
transactions that would require us to issue equity based on our credit rating or
other trigger events.
DEBT COVENANTS
In addition to the limit on our total debt to capitalization ratio imposed
by our committed credit facilities described above, our First Mortgage Bonds
provide for certain cash flow requirements and restrictions on additional
indebtedness, sale of assets and payment of dividends. Under the most
restrictive of such covenants, cumulative cash dividends paid after December 31,
1988 may not exceed the sum of accumulated net income for periods after December
31, 1988 plus $15.0 million. At September 30, 2003, approximately $84.1 million
of retained earnings was unrestricted. We are in compliance with all of our debt
covenants as of September 30, 2003.
The following tables provide information about contractual obligations and
commercial commitments at September 30, 2003.
AEM has commitments to purchase physical quantities of natural gas under
contracts indexed to the forward Nymex strip or fixed price contracts. At
September 30, 2003, AEM was committed to purchase 83.1 Bcf within one year and
24.8 Bcf between 1 to 3 years under indexed contracts. AEM was committed to
purchase 2.2 Bcf within one year under fixed price contracts with prices ranging
from $3.13 to $6.70. AEM's fixed price contracts are marked to market as
derivatives. See further discussion of the fixed price contracts under "Risk
Management and Trading Activities."
PENSION AND POSTRETIREMENT BENEFITS OBLIGATIONS
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. Of the total cash contributed, $26.1 million
represented a 2002 contribution, which was deducted on our 2002 tax return. The
cash contribution was financed through a combination of cash on hand and a
portion of the net proceeds received from the sale of 4,100,000 shares of our
common stock in our 2003 Offering. As a result of this contribution and improved
investment returns during fiscal 2003, the underfunded status of the plan
improved by approximately $8.6 million, and the $39.4 million reduction to
equity recorded in the prior year was eliminated as of September 30, 2003. We
recorded the $39.4 million reduction in equity at September 30, 2002 as a result
of negative investment returns from plan assets during fiscal 2002, lump sum
distributions to participants and a decrease in interest rates. Refer to Note 9
to the consolidated financial statements for further information regarding our
pension plans.
For the fiscal year ended September 30, 2003, our pension cost was $2.7
million compared with pension income of $3.5 million and $8.3 million for the
fiscal years ended September 30, 2002 and 2001. Pension income and expense is
recorded as a component of operation and maintenance expense.
We incurred pension cost during fiscal 2003 compared with income in fiscal
2002 due to an increase in the service cost and interest cost attributable to an
increase in the projected benefit obligation. The increase in the projected
benefit obligation resulted primarily from an increase in the number of plan
participants due to the MVG acquisition and an increase attributable to a 125
basis point decrease in the discount rate used in the fiscal 2003 actuarial
calculations reflecting the decline in market interest rates. The decrease in
pension income between fiscal 2001 and 2002 was attributable to increases in
service cost and interest costs due to increases in the projected benefit
obligations coupled with a decrease in the expected return on assets due to poor
investment performance.
The projected pension liability, future funding requirements and the amount
of pension expense or income recognized for the Plan are subject to change,
depending upon the actuarial value of plan assets and the determination of
future benefit obligations as of each subsequent actuarial calculation date.
These amounts are impacted by actual investment returns, changes in interest
rates and changes in the demographic composition of the participants in the
plan. The actuarial assumptions used to determine the pension liability for our
pension plan are as follows:
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. These rates have declined since fiscal 2001 due to
a decline in interest rates and poor market performance of the underlying plan
assets. The rate of compensation increase is established based upon our internal
budgets. At this time, we anticipate that additional voluntary contributions
ranging from $0 -- $15 million during fiscal 2004 may be necessary to keep the
plan 100% funded on an accumulated benefit obligation basis.
We conduct our risk management activities through both our utility and
natural gas marketing segments. The following table shows our risk management
assets and liabilities by segment at September 30, 2003.
Our utility segment's hedging activities are designed to protect us and our
customers against unusually large winter period gas price increases and include
the use of financial hedges and fixed forward contracts. For the 2002-2003
heating season, we covered approximately 51 percent of our anticipated flowing
gas requirements through a combination of storage, financial hedges and fixed
forward contracts at a weighted average cost of less than $4.00 per Mcf. This
provided a measure of protection to us and our customers against the natural gas
price volatility experienced during the 2002-2003 heating season. For the
2003-2004 heating season, we expect to hedge between 50 percent and 55 percent
of our anticipated flowing gas requirements through a combination of storage and
financial hedges at a weighted average cost of approximately $5.25 per Mcf.
In June 2001, we purchased a three year weather insurance policy with an
option to cancel the third year of coverage. The insurance was designed for our
Texas and Louisiana operations to protect against weather that was at least
seven percent warmer than normal for the entire heating season of October
through March beginning with the 2001-2002 heating season. The cost of the three
year policy was $13.2 million, which was prepaid and amortized over the
appropriate heating seasons based on degree days. Because weather was not at
least seven percent warmer than normal, no income was recognized under this
insurance policy during the years ended September 30, 2003 and 2002.
Amortization expense of $5.0 million and $4.4 million was recognized during the
fiscal years ended September 30, 2003 and 2002. Included in the amortization
expense for the fiscal year ended September 30, 2003 was a third quarter charge
of $0.6 million, net of cash received, related to the cancellation of the third
year of coverage on our weather insurance policy primarily as a result of rate
relief in Louisiana, WNA in certain areas of Texas and prospects for WNA in
other areas of Texas.
Our natural gas marketing segment hedging activities are conducted through
AEM and are designed to manage margins 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.
On October 25, 2002, the Emerging Issues Task Force (EITF) issued EITF
02-03, Accounting for Contracts Involved in Energy Trading and Risk Management,
which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management
Activities, and required that all energy trading contracts entered into after
October 25, 2002 be accounted for pursuant to the provisions of SFAS 133,
Accounting for Derivative Instruments and Hedging Activities. Prior to the
issuance of EITF 02-03, we accounted for all energy trading contracts under the
mark-to-market method in accordance with EITF 98-10. With the adoption of EITF
02-03, our inventory, storage, transportation and index-priced physical forward
contracts are no longer marked to market. Our index-priced physical forward
contracts are now considered normal purchases and sales under SFAS 133.
Accordingly, the carrying value of these contracts was frozen as of January 1,
2003 and will be recognized in earnings concurrent with delivery under the
contracts. We recognized a charge for the
The following table shows the components of the change in fair value of our
utility and natural gas marketing derivative contract activities for the year
ended September 30, 2003 (in thousands).
The fair value of our utility and natural gas marketing derivative
contracts at September 30, 2003, is segregated below, by time period and fair
value source.
Physical trading involves 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.
These trading activities are subject to a risk management policy which
limits the level of trading loss to a maximum of 25 percent of the budgeted
annual operating income of Atmos Energy Holdings. Compliance with this risk
management policy is monitored on a daily basis. In addition, the risk
management policy limits Woodward Marketing's Gas Daily Daily and NYMEX
positions with price risk, including inventory, (open positions) to a total
volume of 5.0 Bcf. We manage our business to maintain no open positions.
However, at times, limited net open positions related to our physical storage
may occur on a short term basis. Woodward Marketing monitors its open trading
positions daily to ensure they are within the limits set by the risk management
policy. At September 30, 2003, Woodward's net open positions in its trading
operations totaled 0.1 Bcf.
RECENT ACCOUNTING DEVELOPMENTS
In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS
150, Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity. SFAS 150 establishes standards for the classification
and measurement of certain financial instruments with characteristics of both
In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies the
accounting and reporting for derivative instruments, including hedges. This
statement amends SFAS 133 for decisions made by the Derivatives Implementation
Group and by the FASB in connection with other projects dealing with financial
instruments, and clarifies other implementation issues. SFAS 149 is effective
for the Company on a prospective basis for contracts entered into or modified
after June 30, 2003. The adoption of this statement did not have a material
impact on our financial position, results of operations or net cash flows.
In January 2003, the FASB issued FASB Interpretation (FIN) 46,
Consolidation of Variable Interest Entities, An Interpretation of Accounting
Research Bulletin No. 51. The primary objectives of FIN 46 are to provide
guidance on how to identify entities for which control is achieved through means
other than through voting rights (variable interest entities (VIE)) and how to
determine when and which business enterprises should consolidate the VIE. This
new model for consolidation applies to an entity in which either (1) the equity
investors do not have a controlling financial interest or (2) the equity
investment at risk is insufficient to finance that entity's activities without
receiving additional subordinated financial support from other parties. FIN 46
applies immediately to VIEs created after January 31, 2003 or to VIEs obtained
after that date. For variable interests held in VIEs acquired prior to February
1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003,
the FASB deferred the effective date of FIN 46 for VIEs created prior to
February 1, 2003 to the first reporting period after December 15, 2003. The
adoption of this interpretation will not have a material impact on our financial
position, results of operations or net cash flows because Atmos currently is not
a primary beneficiary of a VIE.
In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based
Compensation. SFAS 148 provides three transition options for companies that
account for stock-based compensation under the intrinsic method to convert to
the fair value method. SFAS 148 also modified the disclosure requirements for
stock-based compensation to increase the prominence and character of the pro
forma disclosures for entities using the intrinsic value method. Although we
have elected to continue using the intrinsic value method, we adopted the
disclosure requirements prescribed by SFAS 148.
In November 2002, the FASB issued FIN 45, Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN 45 clarifies the requirements of SFAS 5 Accounting
For Obligations, relating to a guarantor's accounting for, and disclosure of the
issuance of certain types of guarantees. The adoption of FIN 45 did not impact
our financial position, results of operations or net cash flows as we currently
do not have any guarantees that meet the recognition and disclosure criteria
outlined in this pronouncement.
In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. Effective October 1, 2002, we adopted SFAS
143, which had no material impact on our financial position or results of
operations based on the perpetual nature of our franchise agreements and on our
experience in the businesses in which we operate.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The risk inherent in our market risk-sensitive instruments is the potential
loss arising from adverse changes in natural gas commodity prices and interest
rates as discussed below. The sensitivity analysis does
GAS PRICES
We purchase natural gas for our utility operations. Substantially all of
the cost of gas purchased for utility operations is recovered from our customers
through purchased gas adjustment mechanisms. The utility segment has limited
market risk in gas prices related to gas purchases in the open market at spot
prices for sale to non-regulated energy services customers at fixed prices. As a
result, our earnings could be affected by changes in the price and availability
of such gas. To protect against volatility in gas prices, we hedge our gas costs
by purchasing futures contracts and by purchasing gas in advance of the winter
heating season and placing it in storage. Our utility segment does not use such
financial instruments for trading purposes and we are not a party to any
leveraged derivatives. Market risk is estimated as a hypothetical 10 percent
increase in the portion of our gas cost related to fixed-price non-regulated
sales. Based on projected fiscal 2004 non-regulated gas sales at fixed prices
based upon the September 30, 2003 three month market strip, such an increase
would result in an increase to cost of gas of approximately $5.7 million in
fiscal 2004.
The principal business of AEM, including the activities of Woodward
Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., is the
overall management of natural gas requirements for municipalities, local gas
utility companies and industrial customers located primarily in the southeastern
and midwestern United States. AEM also supplies our regulated operations with a
portion of our natural gas requirements on a competitive bid basis.
In the management of natural gas requirements for municipalities and other
local utilities, AEM sells physical natural gas to customers for future
delivery. 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. 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 requirement, to buy or sell energy commodities at a fixed
price. AEM links these gas futures to physical delivery of natural gas and
typically balances its futures 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.
Physical trading involves 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.
These trading activities are subject to a risk management policy which
limits the level of trading loss to a maximum of 25 percent of the budgeted
annual operating income of Atmos Energy Holdings. Compliance with this risk
management policy is monitored on a daily basis. In addition, the risk
management policy limits Woodward Marketing's Gas Daily Daily and NYMEX
positions with price risk, including inventory, (open positions) to a total
volume of 5.0 Bcf. We manage our business to maintain no open positions.
However, at times, limited net open positions related to our physical storage
may occur on a short term basis. Woodward Marketing monitors its open trading
positions daily to ensure they are within the limits set by the risk management
policy. At September 30, 2003, Woodward's net open positions in its trading
operations totaled 0.1 Bcf.
Because AEM's operations are concentrated in the natural gas industry, its
customers and suppliers may be subject to economic risks affecting that
industry. Therefore, an economic downturn in the industry could have an adverse
affect on the creditworthiness of AEM's customers. AEM manages credit risk to
attempt to minimize its exposure to uncollectible receivables. In compliance
with AEM's existing credit policy, prospective and existing customers are
reviewed for creditworthiness and customers not meeting minimum standards, at
the discretion of management, provide security deposits and are subject to
various requisite secured payment terms. During 2003, AEM's credit risk has
increased due to higher natural gas prices as compared with the prior year.
However, this risk is somewhat mitigated because a larger percentage of our
business in the current year is with municipal customers, who are typically
rated investment grade, as compared with the prior year.
INTEREST RATES
Our earnings are affected by changes in short-term interest rates as a
result of our issuance of short-term commercial paper and our other short-term
borrowings. If market interest rates for short-term borrowings in fiscal 2003
had averaged one percent more, our interest expense would have increased by
approximately $1.3 million.
Market risk for fixed-rate long-term obligations is estimated as the
potential increase in fair value resulting from a hypothetical one percent
decrease in interest rates and amounts to approximately $72.3 million based on
discounted cash flow analyses.
As of September 30, 2003, we were not engaged in other activities which
would cause exposure to the risk of material earnings or cash flow loss due to
changes in interest rates or market commodity prices.
All other financial statement schedules are omitted because the required
information is not present, or not present in amounts sufficient to require
submission of the schedule or because the information required is included in
the financial statements and accompanying notes thereto.
Board of Directors
We have audited the accompanying consolidated balance sheets of Atmos
Energy Corporation as of September 30, 2003 and 2002, and the related
consolidated statements of income, shareholders' equity and cash flows for each
of the three years in the period ended September 30, 2003. Our audits also
included the financial statement schedule listed in the Index at Item 15(a).
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Atmos Energy Corporation at September 30, 2003 and 2002, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended September 30, 2003, in conformity with accounting principles
generally accepted in the United States. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly, in all material respects, the
information set forth therein.
As discussed in Note 4 to the consolidated financial statements, in fiscal
2002 the Company adopted Statement of Financial Accounting Standards No. 141,
Business Combinations and Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets.
Dallas, Texas
See accompanying notes to consolidated financial statements
See accompanying notes to consolidated financial statements
See accompanying notes to consolidated financial statements
See accompanying notes to consolidated financial statements
1. NATURE OF BUSINESS
Atmos Energy Corporation and its subsidiaries are engaged primarily in the
natural gas utility business as well as certain non-utility businesses. Through
our natural gas utility business, we distribute natural gas through sales and
transportation arrangements to approximately 1.7 million residential,
commercial, public authority and industrial customers through our six regulated
natural gas utility divisions, which cover the following service areas:
(1) Acquired in December 2002. See Note 3.
In addition, we transport natural gas for others through our distribution
system. Our utility business is subject to federal and state regulation and/or
regulation by local authorities in each of the states in which the utility
divisions operate. Our shared services unit is located in Dallas, Texas, and our
customer support centers are located in Amarillo, Texas and Metairie, Louisiana.
Our non-utility businesses are organized under Atmos Energy Holdings, Inc.
and have operations in 18 states. Through September 30, 2003, Atmos Energy
Marketing, LLC, together with its wholly-owned subsidiaries Woodward Marketing,
L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural
gas marketing segment. Effective October 1, 2003, our natural gas marketing
segment was reorganized. The operations of Atmos Energy Marketing, LLC and Trans
Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing,
L.L.C, which was renamed Atmos Energy Marketing, LLC (AEM).
AEM provides a variety of natural gas management services to
municipalities, natural gas utility systems and industrial natural gas consumers
primarily in the southeastern and midwestern states and to our Colorado-Kansas,
Kentucky, Louisiana and Mid-States divisions. These services 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 hedging through the use
of derivative products.
Our other non-utility businesses consist 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, L.L.C, we own or have an interest in underground storage fields in
Kansas, Kentucky and Louisiana. Additionally, Atmos Pipeline and Storage, L.L.C.
contracts for storage service in underground storage facilities on many of the
interstate pipelines serving us.
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.
Finally, 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.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements include the accounts of
Atmos Energy Corporation and its wholly-owned subsidiaries. All material
intercompany transactions have been eliminated. Additionally, effective April 1,
2001, we consolidated the assets, liabilities and results of operations of
Woodward Marketing, L.L.C. Prior to that time, we owned a 45 percent interest in
Woodward Marketing, L.L.C. and accounted for that investment under the equity
method of accounting for investments. Finally, we account for our investment in
USP under the equity method of accounting for investments.
Certain prior year amounts have been reclassified to conform with the
current year presentation.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. The most significant estimates include the
allowance for doubtful accounts, legal and environmental accruals, insurance
accruals, pension and postretirement obligations, deferred income taxes, risk
management and trading activities and the valuation of goodwill,
indefinite-lived intangible assets and other long-lived assets. Actual results
could differ from those estimates.
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
accounting policies recognize the financial effects of the ratemaking and
accounting practices and policies of the various regulatory commissions.
Regulated utility operations are accounted for in accordance with Statement of
Financial Accounting Standards (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 authorized recovery of costs due to
regulatory decisions in their financial statements. As a result, certain costs
are permitted to be capitalized rather than expensed because they can be
recovered through rates.
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. Significant regulatory assets and liabilities as of September 30, 2003
and 2002 included the following:
Merger and integration costs, net are amortized on a straight line basis
over estimated useful lives ranging from 7 to 20 years. During the fiscal years
ended September 30, 2003, 2002 and 2001, we recognized $8.2 million, $6.3
million and $5.8 million in amortization expense related to these costs. These
costs will be substantially amortized in December 2005.
At September 30, 2003, we had rate cases pending in our Kansas and West
Texas jurisdictions. Additionally, we filed a rate case in our Lubbock, Texas
system in October 2003. Finally, we are considering our response to an October
2003 ruling in our Mississippi jurisdiction which denied our request for a rate
increase.
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. For the years ended September
30, 2003, 2002 and 2001, we included unrealized gains (losses) on open contracts
of $6.3 million, ($10.5) million and $4.5 million as a component of natural gas
marketing revenues.
We consider all highly liquid investments with an initial or remaining
maturity of three months or less to be cash equivalents.
Accounts receivable consist of natural gas sales to residential,
commercial, industrial, municipal, agricultural and other customers. 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.
Gas stored underground is valued using the average cost method for all our
utility divisions, except for the Mid-States Division, where it is valued on the
first-in first-out method. Gas stored underground and owned by Atmos Pipeline
and Storage, L.L.C. is valued on the last-in first-out method. Gas in storage
that is retained as cushion gas to maintain reservoir pressure is classified as
property, plant and equipment and is valued at cost.
Utility property, plant and equipment is stated at original cost net of
contributions in aid of construction. The cost of additions includes direct
construction costs, payroll related costs (taxes, pensions and other fringe
benefits), administrative and general costs and an allowance for funds used
during construction. The allowance for funds used during construction represents
the estimated cost of funds used to finance the construction of major projects
and are capitalized in the rate base for ratemaking purposes when the completed
projects are placed in service. Interest expense of $0.8 million, $1.3 million
and $1.2 million was capitalized in 2003, 2002 and 2001.
Major renewals and betterments are capitalized while the costs of
maintenance and repairs are charged to expense as incurred. The costs of large
projects are accumulated in construction in progress until the project is
completed. When the project is completed, tested and placed in service, the
balance is transferred to the utility plant in service account included in the
rate base and depreciation begins.
Utility property, plant and equipment is depreciated at various rates on a
straight-line basis over the estimated useful lives of the assets. The composite
rates are as follows:
At the time property, plant and equipment is retired, the cost, plus
removal expenses less salvage, is charged to accumulated depreciation.
Non-utility property, plant and equipment is stated at cost. Depreciation
is generally computed on the straight-line method for financial reporting
purposes based upon estimated useful lives ranging from 8 to 38 years.
SFAS 143, Accounting for Asset Retirement Obligations which was effective
for us October 1, 2002 requires that we record a liability at fair value for an
asset retirement obligation when the legal obligation to retire the asset has
been incurred with an offsetting increase to the carrying value of the related
asset. Accretion of the asset retirement obligation due to the passage of time
is recorded as an operating expense. As of September 30, 2003, we have no
material asset retirement obligations.
We periodically evaluate whether events or circumstances have occurred that
indicate that 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 long-lived assets by determining
whether the carrying value will be recovered through the expected future cash
flows. In the event the sum of the expected future cash flows resulting from the
use of the asset is less than the carrying value of the asset, an impairment
loss equal to the excess of the asset's carrying value over its fair value is
recorded. To date, no impairment has been recognized.
We annually evaluate our goodwill balances for impairment during our second
fiscal quarter or more frequently as impairment indicators arise. We use a
present value technique based on discounted cash flows to estimate the fair
value of our reporting units. These calculations 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.
Intangible assets are amortized over their useful lives ranging from 3 to
10 years. These assets are reviewed for impairment as impairment indicators
arise. When such events or circumstances are present, we assess the
recoverability of long-lived assets by determining whether the carrying value
will be recovered through the expected future cash flows. In the event the sum
of the expected future cash flows resulting from the use of the asset is less
than the carrying value of the asset, an impairment loss equal to the excess of
the asset's carrying value over its fair value is recorded. To date, no
impairment has been recognized.
As of September 30, 2003 and 2002, all of our marketable securities are
classified as available-for-sale securities based upon the criteria of SFAS 115,
Accounting for Certain Investments in Debt and Equity Securities. In accordance
with that standard, these securities are reported at market value with
unrealized gains and losses shown as a component of accumulated other
comprehensive income (loss). We regularly evaluate the performance of these
investments on a fund by fund basis for impairment, taking into consideration
the fund's volatility and current returns. If a determination is made that a
decline in fair value is other than temporary, the related fund is written down
to its estimated fair value.
Our derivative and hedging activities are tailored to the segment to which
they relate. We record our derivatives as a component of risk management assets
and liabilities, which are classified as current or noncurrent, based upon the
anticipated settlement date of the underlying derivative. These assets and
liabilities are recorded as components of other current assets, deferred charges
and other assets, other current liabilities or deferred credits and other
liabilities depending on the expiration or maturity date of the instrument.
We use a combination of storage and financial hedges to protect us and our
customers against unusually large winter period gas price increases. Our
financial hedges are accounted for under the mark-to-market method pursuant to
SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However,
because these costs will ultimately be recovered through our rates, current
period changes in the assets and liabilities from risk management activities are
recorded as a component of deferred gas costs in accordance with SFAS 71 and
recognized in purchased gas cost in the income statement when the related costs
are
recovered through our rates. Accordingly, there is no earnings impact as a
result of the use of these financial instruments.
The principal business of AEM is the overall management of natural gas
requirements for municipalities, local gas utility companies and industrial
customers located primarily in the southeastern and midwestern United States.
AEM also supplies our regulated operations with a portion of our natural gas
requirements on a competitive bid basis.
In the management of natural gas requirements for municipalities and other
local utilities, AEM sells physical natural gas to customers for future
delivery. 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 financial derivatives,
including forwards, over-the-counter and exchange-traded options and swap
contracts with counterparties. 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 requirement, to buy or sell energy
commodities at a fixed price. AEM links these financial derivatives to physical
delivery of natural gas 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.
Physical trading involves 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.
These trading activities are subject to a risk management policy which
limits the level of trading loss to a maximum of 25 percent of the budgeted
annual operating income of Atmos Energy Holdings. Compliance with this risk
management policy is monitored on a daily basis. In addition, the risk
management policy limits Woodward Marketing's Gas Daily Daily and NYMEX
positions with price risk, including inventory, (open positions) to a total
volume of 5.0 Bcf. We manage our business to maintain no open positions.
However, at times, limited net open positions related to our physical storage
may occur on a short term basis. Woodward Marketing's open trading positions are
monitored daily but are not required to be closed if they remain within the
limits set by the bank loan agreement.
Those futures contracts that are designated as fair value hedges in
accordance with SFAS 133 are recorded at fair value on the balance sheet with an
offsetting adjustment to the underlying item being hedged. Those financial
contracts that are not designated as hedges are recorded on the balance sheet at
fair value with current period changes in these contracts recorded as net gains
or losses in our natural gas marketing revenue on the consolidated statement of
income. Generally, any price risk related to fixed price forward contracts that
are marked to market through earnings is mitigated by offsetting futures
contracts that are also marked to market through earnings. Any mark-to-market
gains or losses on affiliate contracts are eliminated in consolidation.
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 estimate 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 directly affect our estimate of the
fair value of these transactions.
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 demographical data. 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. 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.
Income taxes are provided based on the liability method, which results in
income tax assets and liabilities arising from temporary differences. Temporary
differences are differences between the tax bases of assets and liabilities and
their reported amounts in the financial statements that will result in taxable
or deductible amounts in future years. The liability method requires the effect
of tax rate changes on current and accumulated deferred income taxes to be
reflected in the period in which the rate change was enacted. The liability
method also requires that deferred tax assets be reduced by a valuation
allowance unless it is more likely than not that the assets will be realized.
We have two stock-based compensation plans that provide for the granting of
incentive stock options, non-qualified stock options, stock appreciation rights,
bonus stock, restricted stock and performance-based stock to officers, key
employees and non-employee directors: the 1998 Long-Term Incentive Plan and the
Long-Term Stock Plan for the Mid-States Division. The objectives of these plans
include attracting and retaining the best personnel, providing for additional
performance incentives and promoting our success by providing employees with the
opportunity to acquire common stock. These plans are more fully described in
Note 8. As permitted by SFAS 123, Accounting for Stock-Based Compensation we
account for these plans under the intrinsic value method described in Accounting
Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees.
Under this method, no compensation cost for stock options is recognized for
stock option awards granted at or above fair market value.
Awards of restricted stock are generally valued at the market price of the
Company's common stock on the date of grant. The unearned compensation is
amortized to operation and maintenance expense over the vesting period of the
restricted stock.
Had compensation expense for our stock options been recognized based on the
fair value on the grant date under the methodology prescribed by SFAS 123, our
net income and earnings per share for the years ended September 30, 2003, 2002
and 2001 would have been impacted as shown in the following table:
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
143, Accounting for Asset Retirement Obligations. This Statement addresses
financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. Effective October 1, 2002, we adopted SFAS 143, which had no material
impact to our financial position or results of operations based on the perpetual
nature of our franchise agreements and on our experience in the businesses in
which we operate.
As more fully described in Note 5, on October 25, 2002, the Emerging Issues
Task Force (EITF) issued EITF 02-03, Accounting for Contracts Involved in Energy
Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy
Trading and Risk Management Activities, and required that all energy trading
contracts entered into after October 25, 2002 be accounted for pursuant to the
provisions of SFAS 133, Accounting for Derivative Instruments and Hedging
Activities. Prior to the issuance of EITF 02-03, we accounted for all energy
trading contracts under the mark-to-market method in accordance with EITF 98-10.
Upon the adoption of EITF 02-03, our inventory, storage, transportation and
index-priced physical forward contracts are no longer marked to market. Our
index-priced physical forward contracts are now considered normal purchases and
sales under SFAS 133. Accordingly, the carrying value of these contracts was
frozen as of January 1, 2003 and will be recognized in earnings concurrent with
delivery under the contracts. We recognized a charge for the cumulative effect
of accounting change of $7.8 million, net of income tax benefit, upon the
adoption of EITF 02-03 in the second quarter of fiscal 2003. Fixed price
contracts generally continue to be marked to market. In conjunction with the
adoption of EITF 02-03, energy trading contracts resulting in delivery of a
commodity where we are the principal in the transaction are included as natural
gas marketing sales or purchases. All prior periods have been reclassified to
conform with this new presentation.
In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based
Compensation. SFAS 148 provides three transition options for companies that
account for stock-based compensation under the intrinsic method to convert to
the fair value method. SFAS 148 also modified the disclosure requirements for
stock-based compensation to increase the prominence and character of the pro
forma disclosures for entities using
the intrinsic value method. Although we have elected to continue using the
intrinsic value method, we adopted the disclosure requirements prescribed by
SFAS 148.
In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies the
accounting and reporting for derivative instruments, including hedges. This
statement amends SFAS 133 for decisions made by the Derivatives Implementation
Group and by the FASB in connection with other projects dealing with financial
instruments, and clarifies other implementation issues. SFAS 149 is effective
for the Company on a prospective basis for contracts entered into or modified
after June 30, 2003. The adoption of this statement did not have a material
impact on our financial position, results of operations or net cash flows.
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity. SFAS 150
establishes standards for the classification and measurement of certain
financial instruments with characteristics of both liabilities and equity. Under
SFAS 150, mandatorily redeemable financial instruments, obligations to
repurchase the issuer's shares by transferring assets and certain obligations to
issue a variable number of shares to settle that obligation must be classified
as liabilities on the balance sheet and initially recorded at fair value. SFAS
150 is effective for the Company for financial instruments entered into or
modified after May 31, 2003, and on July 1, 2003 for most previously existing
financial instruments. In November 2003, the FASB voted to defer indefinitely
the effective date for certain mandatorily redeemable non-controlling interests
(MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the
effective date was deferred to November 5, 2003. The adoption of SFAS 150 did
not impact our financial position, results of operations or net cash flows as we
currently do not use any of the financial instruments subject to this statement.
In November 2002, the FASB issued FASB Interpretation (FIN) 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others. FIN 45 clarifies the requirements of SFAS
5, Accounting For Obligations, relating to a guarantor's accounting for, and
disclosure of the issuance of certain types of guarantees. The adoption of FIN
45 did not impact our financial position, results of operations or net cash
flows as we currently do not have any guarantees that meet the recognition and
disclosure criteria outlined in this pronouncement.
In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest
Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary
objectives of FIN 46 are to provide guidance on how to identify entities for
which control is achieved through means other than through voting rights
(variable interest entities (VIE)) and how to determine when and which business
enterprises should consolidate the VIE. This new model for consolidation applies
to an entity in which either (1) the equity investors do not have a controlling
financial interest or (2) the equity investment at risk is insufficient to
finance that entity's activities without receiving additional subordinated
financial support from other parties. FIN 46 applies immediately to VIEs created
after January 31, 2003 or to VIEs obtained after that date. For variable
interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally
effective July 1, 2003. However, in October 2003, the FASB deferred the
effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first
reporting period after December 15, 2003. The adoption of this interpretation
will not have a material impact on our financial position, results of operations
or net cash flows because Atmos currently is not a primary beneficiary of a VIE.
3. ACQUISITIONS
On December 3, 2002, we completed the acquisition of Mississippi Valley Gas
Company (MVG), Mississippi's largest natural gas utility, which enabled us to
expand our service area into Mississippi. MVG served approximately 261,500
residential, commercial, industrial and other customers located primarily in the
northern and central regions of Mississippi. We paid approximately $74.7 million
in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287
unregistered shares. We also repaid approximately $70.9 million of MVG's
outstanding debt. The results of operations of MVG have been consolidated with
our results of operations from the acquisition date.
The following table summarizes the fair values of the assets acquired and
liabilities assumed, in thousands:
The value assigned to goodwill was based on our belief that the acquisition
of MVG will enable us to leverage our existing technology in order to add value
to Atmos. This goodwill is not deductible for tax purposes. Other
acquisition-related costs consist of $13.1 million of make-whole premiums
related to the repayment of MVG's debt and other costs including termination
benefits.
The table below reflects the unaudited pro forma results of the Company and
MVG for the years ended September 30, 2003 and 2002 as if the acquisition had
taken place at the beginning of fiscal 2002.
In April 2001, we acquired from Woodward Marketing, Inc. the 55 percent
interest in Woodward Marketing, L.L.C. that we did not already own in exchange
for 1,423,193 restricted shares of our common stock with a value of $26.7
million. The consideration is subject to a potential upward adjustment, based on
our share price, of up to 232,547 shares plus an amount of shares to compensate
for dividends paid after the completion of the acquisition. The adjustment
period expires on March 31, 2006.
Effective July 1, 2001, we acquired the assets of Louisiana Gas Service
Company and LGS Natural Gas Company (collectively referred to as LGS) for $363.4
million. The acquired assets provide natural gas
distribution service through approximately 279,000 residential and commercial
meters in southeastern and northern Louisiana. The service territory includes
the suburban areas of metropolitan New Orleans (excluding Orleans Parish), the
north shore of Lake Pontchartrain and the Monroe/West Monroe metropolitan area.
The non-utility operations include a natural gas marketing company and an
intrastate pipeline company which provides gas transportation service to
industrial customers in Louisiana and to the acquired assets. The acquisition
increased the size of our operations in Louisiana and allowed us to achieve
certain synergies and cost savings by combining the acquired operations with our
existing Louisiana operations. The acquisition was financed through the issuance
of $350.0 million of unsecured 7.375% Senior Notes due in 2011.
4. GOODWILL AND INTANGIBLE ASSETS
Goodwill and intangible assets are comprised of the following as of
September 30, 2003 and 2002.
The following presents our goodwill balance allocated by segment and
changes in our balance for the year ended September 30, 2003:
Effective October 1, 2001, we adopted the provisions of SFAS 142, Goodwill
and Other Intangible Assets. Goodwill applicable to the utility segment
primarily arose from our July 1, 2001 acquisition of the assets of LGS and our
December 3, 2002 acquisition of MVG. This goodwill is not subject to
amortization under SFAS 142. Goodwill applicable to the Natural Gas Marketing
Segment was amortized over 20 years prior to the adoption of SFAS 142. The
proforma effect of adopting SFAS 142 would be to increase net income by $0.3
million for fiscal 2001.
SFAS 142 requires that we evaluate our goodwill balances for impairment on
an annual basis or when impairment indicators arise. We performed our annual
evaluation during the quarter ended March 31, 2003 which resulted in no
impairment. No indicators have arisen since that time that would indicate that
our goodwill balance is impaired.
Information regarding our intangible assets is included in the following
table. As of September 30, 2003 and 2002, we had no indefinite-lived intangible
assets:
The following table presents actual amortization expense recognized during
2003 and an estimate of future amortization expense based upon our intangible
assets at September 30, 2003.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We conduct our risk management activities through both our utility and
natural gas marketing segments. The following table shows our risk management
assets and liabilities by segment at September 30, 2003 and 2002:
The following table shows the components of the change in fair value of our
utility and natural gas marketing derivative contract activities for the year
ended September 30, 2003 (in thousands).
For the 2002-2003 heating season, we covered approximately 51 percent of
our anticipated flowing gas requirements through a combination of storage,
financial hedges and fixed forward contracts at a weighted average cost of less
than $4.00 per Mcf. This provided a measure of protection to us and our
customers against the natural gas price volatility experienced during the
2002-2003 winter heating season.
Our non-utility hedging activities are conducted through AEM. AEM manages
margins and limits risk exposure on natural gas inventory, fixed-price physical
forwards, and purchases and sales of Gas Daily Daily natural gas through the use
of financial derivatives, including futures, over-the-counter and
exchange-traded options and swap contracts with counterparties. We manage our
business to maintain no open positions. However, at times, limited net open
positions related to our physical storage may occur on a short term basis. At
the close of business on September 30, 2003 and 2002, AEM had a net open
position (including inventory) of 0.1 Bcf and 1.9 Bcf. As of September 2003 and
2002, contracts representing 99 and 97 percent of the fair value of these
contracts are scheduled to mature within three years.
Financial instruments, which subject AEM to counterparty risk, consist
primarily of financial instruments arising from trading and risk management
activities that are not insured. Counterparty risk is the risk of loss from
nonperformance by financial counterparties to a contract. Exchange-traded future
and option contracts are generally guaranteed by the exchanges.
On October 25, 2002, the EITF issued EITF 02-03, Accounting for Contracts
Involved in Energy Trading and Risk Management, which rescinded EITF 98-10,
Accounting for Energy Trading and Risk Management Activities, and required that
all energy trading contracts entered into after October 25, 2002 be accounted
for pursuant to the provisions of SFAS 133, Accounting for Derivative
Instruments and Hedging Activities. Prior to the issuance of EITF 02-03, we
accounted for all energy trading contracts under the mark-to-market method in
accordance with EITF 98-10.
Prior to December 31, 2002, we had recorded $12.9 million ($7.8 million,
net of tax) of unrealized income related to our storage and transportation
contracts and certain full requirements contracts in accordance with EITF 98-10.
On January 1, 2003, we reversed this unrealized income, which was reported as a
non-cash cumulative effect of a change in accounting principle in accordance
with APB 20, Accounting Changes.
Additionally, beginning January 1, 2003, all energy trading contracts are
being accounted for pursuant to the provisions of SFAS 133. As a result, many of
our index-priced physical forward contracts qualify for the normal purchases and
sales exception under SFAS 133 and are not marked to market for changes in value
subsequent to December 31, 2002. The carrying value of these contracts as of
January 1, 2003 was frozen and will be recognized in earnings concurrent with
delivery under the contracts. Fixed price contracts generally continue to be
marked to market. In conjunction with the adoption of EITF 02-03, energy trading
contracts resulting in delivery of a commodity where we are the principal in the
transaction are included as natural gas marketing sales or purchases. All prior
year periods have been reclassified to conform with this new presentation.
Finally, effective January 1, 2003, we designated a portion of our futures
contracts as fair value hedges of the natural gas marketing segment's gas
inventory. Accordingly, the inventory was adjusted to cost as of January 1, 2003
as part of the cumulative effect adjustment, and subsequent changes in fair
value will be recognized as an adjustment to the carrying value of the hedged
inventory.
In June 2001, we purchased a three year weather insurance policy with an
option to cancel the third year of coverage. The insurance was designed for our
Texas and Louisiana operations to protect against weather that was at least
seven percent warmer than normal for the entire heating season of October
through March beginning with the 2001-2002 heating season. The cost of the three
year policy was $13.2 million, which was prepaid and was amortized over the
appropriate heating seasons based on degree days. Amortization expense of $5.0
million and $4.4 million was recognized during the fiscal years ended September
30, 2003 and 2002. Included in the amortization expense for fiscal 2003 was a
third quarter charge of $0.6 million, net of cash received, related to the
cancellation of the third year of coverage on our weather insurance policy
primarily as a result of rate relief in Louisiana and prospects for weather
normalization adjustments in Texas. Because weather was not at least seven
percent warmer than normal, no income was recognized under this insurance policy
during fiscal 2003 and 2002.
6. DEBT
Long-term debt at September 30, 2003 and 2002 consisted of the following:
Most of the First Mortgage Bonds contain provisions that allow us to prepay
the outstanding balance in whole at any time, subject to a prepayment premium.
The First Mortgage Bonds provide for certain cash flow requirements and
restrictions on additional indebtedness, sale of assets and payment of
dividends. Under the most restrictive of such covenants, cumulative cash
dividends paid after December 31, 1988 may not exceed the sum of accumulated net
income for periods after December 31, 1988 plus $15.0 million. At
September 30, 2003, approximately $84.1 million of retained earnings was
unrestricted. We are in compliance with all of our debt covenants as of
September 30, 2003.
In December 2001, we filed a shelf registration statement with the
Securities and Exchange Commission (SEC) to issue, from time to time, up to
$600.0 million in new common stock and/or debt. The registration statement was
declared effective by the SEC on January 30, 2002. On January 16, 2003, we
issued $250.0 million of 5 1/8% Senior Notes due 2013 under the registration
statement. The net proceeds of $249.3 million were used to repay debt under an
acquisition credit facility used to finance our acquisition of MVG, to repay
$54.0 million in unsecured senior notes held by institutional lenders and
short-term debt under our commercial paper program and to provide funds for
general corporate purposes. Additionally, as further discussed in Note 7, we
sold 4,100,000 shares of our common stock in connection with our 2003 Offering
under the registration statement. After the debt offering and these common stock
sales, approximately $246.0 million remains available under the shelf
registration statement.
As of September 30, 2003, all of the Colorado-Kansas Division utility plant
assets with a net book value of approximately $194.5 million were subject to a
lien under the 9.4 percent Series J First Mortgage Bonds assumed by us in the
acquisition of Greeley Gas Company. Also, substantially all of the Mid-States
Division utility plant assets, totaling $345.1 million, were subject to a lien
under the Indenture of Mortgage of the Series P through V First Mortgage Bonds.
Based on the borrowing rates currently available to us for debt with
similar terms and remaining average maturities, the fair value of long-term debt
at September 30, 2003 and 2002 is estimated, using discounted cash flow
analysis, to be $1,003.9 million and $775.5 million.
Maturities of long-term debt at September 30, 2003 were as follows (in
thousands):
At September 30, 2003, short-term debt consisted of $118.6 million of
commercial paper. At September 30, 2002, short-term debt was composed of $132.7
million of commercial paper and $13.1 million outstanding under bank credit
facilities. The weighted average interest rate on short-term borrowings
outstanding was 1.7 percent and 2.3 percent at September 30, 2003 and 2002.
We maintain both committed and uncommitted credit facilities. Our credit
capacity and the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term borrowing
requirements, which are typically highest during colder months. Our working
capital needs can vary significantly due to changes in the price of natural gas
charged by suppliers and the increased gas supplies required to meet customers'
needs during periods of cold weather.
We have two short-term committed credit facilities totaling $368.0 million.
The first short-term unsecured credit facility is for $350.0 million, bears
interest at the Eurodollar rate plus 0.625 percent and serves as a backup
liquidity facility for our commercial paper program. This facility was renewed
in July 2003 with a $50.0 million increase in the amount of the facility under
substantially the same terms as those of the prior facility. This facility will
expire in July 2004. At September 30, 2003, $118.6 million of commercial paper
was outstanding, and Atmos Energy Corporation letters of credit reduced the
amount available by an additional $2.4 million. We have a second unsecured
facility in place for $18.0 million that bears interest at the Fed Funds rate
plus 0.5 percent. At September 30, 2003, there were no borrowings under this
credit facility. These credit facilities are negotiated at least annually and
are used for working capital purposes.
On October 7, 2002, we entered into a $150.0 million short-term unsecured
committed credit facility. This credit facility was used to provide initial
funding for the cash portion of the MVG acquisition and to repay MVG's existing
debt. A total of $147.0 million was borrowed under this credit facility during
the first quarter. This amount was refinanced in January 2003 with a portion of
the proceeds of our $250.0 million debt offering, as discussed above.
The availability of funds under our credit facilities is subject to
conditions specified therein, which we currently meet. These conditions include
our compliance with financial covenants and the continued accuracy of
representations and warranties contained in these agreements. We are required by
the financial covenants in our $350.0 million credit facility to maintain a
ratio of total debt to total capitalization of no greater than 70 percent. At
September 30, 2003, our total debt to total capitalization ratio, as defined,
was 55 percent.
Our Woodward Marketing subsidiary has a $210.0 million uncommitted demand
working capital credit facility that bears interest at LIBOR plus 2.5 percent.
Atmos Energy Holdings, Inc. (AEH) and AEM, our wholly-owned subsidiaries, are
guarantors of all amounts outstanding under this facility. Effective October 1,
2003 with the reorganization of our natural gas marketing segment, AEM became
the borrower under the credit facility and AEH became the sole guarantor of the
facility. At September 30, 2003, no amount was outstanding under this credit
facility, although Woodward Marketing, L.L.C. letters of credit totaling $76.9
million reduced the amount available. The amount available under this credit
facility is also limited by various covenants, including covenants based on
working capital. Under the most restrictive covenant, the amount available to
Woodward Marketing under this credit facility at September 30, 2003 was $28.3
million. This credit facility expires on March 31, 2004 and is expected to be
renewed at that time.
We also have an unsecured short-term uncommitted credit line for $20.0
million. There were no borrowings under this uncommitted credit facility at
September 30, 2003. This uncommitted line is renewed or renegotiated at least
annually with varying terms and we pay no fee for the availability of the line.
Borrowings under this line are made on a when and as-available basis at the
discretion of the bank. This facility is also used for working capital purposes.
In October 2003, we increased the amount of this credit line to $25.0 million.
In addition, Woodward Marketing has a $100.0 million intercompany credit
facility with AEH for its non-utility business which bore interest at LIBOR plus
7. SHAREHOLDERS' EQUITY
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.
We have a Rights Agreement under which each right (Right) will entitle the
holder thereof, until May 10, 2008 or the date of redemption of the Rights, to
buy 1/10 of one share of Common Stock of Atmos at the exercise price of $8.00,
subject to adjustment. At no time will the Rights have any voting rights. The
exercise price payable and the number of shares of Common Stock or other
securities or property issuable upon exercise of the Rights are subject to
adjustment from time to time to prevent dilution. At the date upon which the
Rights become separate from our Common Stock (the Distribution Date), we will
issue one right with each share of Common Stock that becomes outstanding so that
all shares of Common Stock will have attached Rights. After the Distribution
Date, we may issue Rights when we issue Common Stock if the Board deems such
issuance to be necessary or appropriate.
The Rights will separate from the Common Stock and a Distribution Date will
occur upon the occurrence of certain events specified in the Rights Agreement,
including but not limited to, the acquisition by certain persons of at least 15
percent of the beneficial ownership of our Common Stock. The Rights have certain
anti-takeover effects and may cause substantial dilution to a person or entity
that attempts to acquire the Company on terms not approved by the Board of
Directors except pursuant to an offer conditioned upon a substantial number of
Rights being acquired. The Rights should not interfere with any merger or other
business combination approved by the Board of Directors because, prior to the
time that the Rights become exercisable or transferable, the Rights may be
redeemed by us at $.01 per Right.
8. STOCK AND OTHER COMPENSATION PLANS
We have two stock-based compensation plans that provide for the granting of
stock options and restricted stock to officers, key employees and non-employee
directors: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for
the Mid-States Division. The objectives of these plans include attracting and
retaining the best personnel, providing for additional performance incentives
and promoting our success by providing employees with the opportunity to acquire
common stock.
1998 Long-Term Incentive Plan
On August 12, 1998, the Board of Directors approved and adopted the 1998
Long-Term Incentive Plan, which became effective October 1, 1998 after approval
by the shareholders of Atmos. The Long-Term Incentive Plan is a comprehensive,
long-term incentive compensation plan providing for discretionary awards of
incentive stock options, non-qualified stock options, stock appreciation rights,
bonus stock, restricted stock and performance-based stock to help attract,
retain and reward employees and non-employee directors of Atmos and its
subsidiaries. We are authorized to grant awards for up to a maximum of 4,000,000
shares of common stock under this plan subject to certain adjustment provisions.
As of September 30, 2003, non-qualified stock options, bonus stock and
restricted stock have been issued under this plan, and 1,923,464 shares were
available for issuance. The option price of the stock options issued under this
plan is equal to the market price of our stock at the date of grant. These stock
options expire 10 years from the date of the grant and vest annually over a
service period ranging from one to three years.
A summary of activity for grants of stock options under the 1998 Long-Term
Incentive Plan follows:
Information about outstanding and exercisable options under the Long-Term
Incentive Plan, as of September 30, 2003, follows:
The stock options had a weighted average fair value per share on the date
of grant of $3.32 in 2003, $3.55 in 2002 and $3.97 in 2001. We used the
Black-Scholes pricing model to estimate the fair value of each option granted
with the following weighted average assumptions for 2003, 2002 and 2001:
Prior to the merger with Atmos, certain United Cities Gas Company officers
and key employees participated in the United Cities Long-Term Stock Plan
implemented in 1989. At the time of the merger on July 31, 1997, Atmos adopted
this plan by registering a total of 250,000 shares of Atmos stock to be issued
under the Long-Term Stock Plan for the Mid-States Division. Under this plan,
incentive stock options, nonqualified stock options, stock appreciation rights,
restricted stock or any combination thereof may be granted to officers and key
employees of the Mid-States Division. Options granted under the plan become
exercisable at a rate of 20 percent per year and expire 10 years after the date
of grant. No awards have been
granted under this plan since 1996. During 2003, 13,000 options were exercised
under the plan. At September 30, 2003, there were 6,300 options outstanding, all
of which were fully vested. Because of the limited activities of this plan, the
pro forma effects of applying SFAS 123 would have less than a $0.01 per diluted
share effect on earnings per share.
As noted above, the 1998 Long-Term Incentive Plan provides for
discretionary awards of restricted stock to help attract, retain and reward
employees and non-employee directors of Atmos and its subsidiaries.
Additionally, from October 1, 1987 through February 2002, we maintained a
Restricted Stock Grant Plan for our management and key employees, which provided
awards of common stock that were subject to certain restrictions. This plan was
administered by the non-employee members of the Board of Directors, who made
final determinations regarding participation in the Plan, awards under the Plan
and restrictions on the restricted stock awarded. The following summarizes
information regarding the restricted stock plans:
We maintain a Direct Stock Purchase Plan which allows participants to have
all or part of their dividends reinvested at a three percent discount from
market prices. Direct Stock Purchase Plan participants may purchase additional
shares of Atmos common stock as often as weekly with voluntary cash payments of
at least $25, up to an annual maximum of $100,000.
In November 1994, the Board adopted the Outside Directors Stock-for-Fee
Plan which was approved by the shareholders of Atmos in February 1995 and was
amended and restated in November 1997. The plan permits non-employee directors
to receive all or part of their annual retainer and meeting fees in stock rather
than in cash.
In November 1998, the Board of Directors adopted the Equity Incentive and
Deferred Compensation Plan for Non-Employee Directors which was approved by the
shareholders of Atmos in February 1999. This plan amended the Atmos Energy
Corporation Deferred Compensation Plan for Outside Directors adopted by the
Company on May 10, 1990 and replaced the pension payable under the Company's
Retirement Plan for Non-Employee Directors. The plan provides non-employee
directors of Atmos with the opportunity to defer receipt of compensation for
services rendered to the Company, invest deferred compensation into either a
cash account or a stock account and to receive an annual grant of share units
for each year of service on the Board.
The Variable Pay Plan was created to give each employee an opportunity to
share in the success of Atmos based on the achievement of key performance
measures considered critical to achieving business objectives for
a given year. These performance measures may include earnings growth objectives,
improved cash flow objectives or crucial customer satisfaction and safety
results. We monitor progress towards the achievement of the performance measures
throughout the year and record accruals based upon the expected payout using the
best estimates available at the time the accrual is recorded.
9. RETIREMENT AND POST-RETIREMENT EMPLOYEE BENEFIT PLANS
We have both funded and unfunded noncontributory defined benefit plans that
together cover substantially all of our employees. We also maintain a
post-retirement plan that provides health care benefits to retired employees.
Finally, we sponsor a defined contribution plan which covers substantially all
employees. These plans are discussed in further detail below.
As of September 30, 2003, we maintain two defined benefit plans: the Atmos
Energy Corporation Pension Account Plan and the Atmos Energy Corporation
Retirement Plan for Mississippi Valley Gas Union Employees. Both plans are held
within the Atmos Energy Corporation Master Retirement Trust.
The Atmos Energy Corporation Pension Account Plan (the Plan) was
established effective January 1, 1999 and covers substantially all employees of
Atmos. Opening account balances were established for participants as of January
1, 1999 equal to the present value of their respective accrued benefits under
the pension plans which were previously in effect as of December 31, 1998. The
Plan credits an allocation to each participant's account at the end of each year
according to a formula based on the participant's age, service and total pay
(excluding incentive pay).
The Plan also provides for an additional annual allocation based upon a
participant's age as of January 1, 1999 for those participants who were
participants in the prior pension plans. The Plan will credit this additional
allocation each year through December 31, 2008. In addition, at the end of each
year, a participant's account will be credited with interest on the employee's
prior year account balance. A special grandfather benefit also applies through
December 31, 2008, for participants who were at least age 50 as of January 1,
1999, and who were participants in one of the prior plans on December 31, 1998.
Participants fully vest in their account balances after five years of service
and may choose to receive their account balances as a lump sum or an annuity.
MVG maintained a defined benefit plan that covered substantially all
full-time employees. On June 30, 2003, all retirees and the active non-union
employees became eligible to participate in the Plan. Active union employees
will remain in MVG's plan, which was renamed the Atmos Energy Corporation
Retirement Plan for Mississippi Valley Gas Union Employees on July 1, 2003.
Under this plan, benefits are based upon years of benefit service and average
final earnings. Participants vest in the plan after five years and will receive
their benefit in an annuity.
Generally, our funding policy is to contribute annually an amount in
accordance with the requirements of the Employee Retirement Income Security Act
of 1974. However, additional voluntary contributions are made from time to time
as considered necessary. Contributions are intended to provide not only for
benefits attributed to service to date but also for those expected to be earned
in the future.
The Plan's assets consist primarily of investments in common stocks,
interest bearing securities and interests in commingled pension trust funds. The
following table presents the Plan's funded status for 2003 and 2002.
The actuarial assumptions used to determine the pension liability for the
Plan are as follows:
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. Of the total cash contributed, $26.1 million
represented a 2002 contribution, which was deducted on our 2002 tax return. The
cash contribution was financed through a combination of cash on hand and a
portion of the net proceeds received from the sale of 4,100,000 shares of our
common stock in our 2003 Offering. As a result of this contribution and improved
investment returns during fiscal 2003, the under funded status of the plan
improved by approximately $8.6 million, and the $39.4 million reduction to
equity recorded in the prior year was eliminated as of September 30, 2003.
The Plan was underfunded at September 30, 2002 primarily due to negative
investment returns from plan assets during fiscal 2002, lump sum distributions
to participants and a decrease in interest rates. As a result, we
recorded a minimum pension liability of $63.6 million before applicable income
taxes as of September 30, 2002, which decreased shareholders' equity by $39.4
million.
Net periodic pension cost for the Plan for 2003, 2002 and 2001 is recorded
as a component of operating expense and included the following components:
We have a nonqualified Supplemental Executive Benefits Plan which provides
additional pension, disability and death benefits to the officers and certain
other employees of Atmos. The Supplemental Plan was amended and restated in
August 1998. In addition, in August 1998, we adopted the Performance-Based
Supplemental Executive Benefits Plan which covers all employees who become
officers or division presidents after August 12, 1998 or any other employees
selected by our Board of Directors in its discretion.
The following table presents the funded status of the supplemental plans
for 2003 and 2002:
The net liability for the supplemental plans is recorded as a component of
deferred credits and other liabilities.
The actuarial assumptions used to determine the pension liability for the
supplemental plans are as follows:
Assets for the supplemental plans are held in separate rabbi trusts and
comprise the following:
Net periodic pension cost for the supplemental plans for 2003, 2002 and
2001 is recorded as a component of operating expense and included the following
components:
Supplemental Disclosures For Defined Benefit Plans with Accumulated Benefit
Obligations in Excess of Plan Assets
The following summarizes key information for defined benefit plans with
accumulated benefit obligations in excess of plan assets:
Prior to January 1, 1999, Atmos sponsored two postretirement plans other
than pensions that provided health care benefits to retired employees. One plan
provided benefits to the Mid-States Division retirees and the other plan
provided medical benefits to all other retired Atmos employees. Effective
January 1, 1999, the
Mid-States plan was merged into the Atmos plan and began providing benefits to
future retirees that are essentially the same as provided to other Atmos
employees.
Substantially all of our employees become eligible for these benefits if
they reach retirement age while working for us and attain certain specified
years of service. In addition, participant contributions are required under the
plan.
The plan assets consist primarily of investments in registered investment
companies and common/ collective trusts.
The following table presents the funding status for the postretirement plan
for 2003 and 2002.
The current portion of the accrued post-retirement cost is recorded as a
component of other current liabilities and the long-term portion of the accrued
post-retirement cost is recorded as a component of deferred credits and other
liabilities.
The actuarial assumptions used to determine the liability for the
post-retirement plan are as follows:
Net periodic postretirement cost for 2003, 2002 and 2001 is recorded as a
component of operating expense and included the following components:
Assumed health care cost trend rates have a significant effect on the
amounts reported for the plan. A one-percentage point change in assumed health
care cost trend rates would have the following effects on the latest actuarial
calculations:
We are currently recovering other postretirement benefits costs through our
regulated rates under SFAS 106 accrual accounting in Colorado, Kansas, the
majority of the Texas service area and Kentucky. We receive rate treatment as a
cost of service item for other postretirement benefits costs on the
pay-as-you-go basis in Louisiana. Other postretirement benefits costs have been
specifically addressed in rate orders in each jurisdiction served by the
Mid-States Division or have been included in a rate case and not disallowed.
Management believes that accrual accounting in accordance with SFAS 106 is
appropriate and will continue to seek rate recovery of accrual-based expenses in
its ratemaking jurisdictions that have not yet approved the recovery of these
expenses.
Atmos sponsors a Retirement Savings Plan for substantially all employees,
which is subject to the provisions of Section 401(k) of the Internal Revenue
Code. Effective January 1, 1999 the Retirement Savings Plan was amended to allow
the deferral of a portion of a participant's salary ranging from a minimum of
one percent of eligible compensation, as defined by the Plan, up to the maximum
allowed by the Internal Revenue Service. We match 100 percent of a participant's
contributions, limited to four percent of the participant's salary, in Atmos
common stock. However, participants have the option to immediately transfer this
matching
contribution into other funds held within the plan. Participants are also
permitted to take out loans against their accounts subject to certain
restrictions. Matching contributions to the Plan are expensed as incurred and
amounted to $4.1 million, $3.6 million, and $3.2 million for 2003, 2002 and
2001. The Board of Directors may also approve discretionary contributions,
subject to the provisions of the Internal Revenue Code of 1986 and applicable
regulations of the Internal Revenue Service. No discretionary contributions were
made for 2003, 2002 or 2001. At September 30, 2003 and 2002, the Retirement
Savings Plan held 4.4 percent and 5.8 percent of our common stock.
10. DETAILS OF SELECTED CONSOLIDATED BALANCE SHEET CAPTIONS
The following tables provide additional information regarding the
composition of certain of our balance sheet captions.
Other current assets as of September 30, 2003 and 2002 are comprised of the
following accounts.
Property, plant and equipment is comprised of the following as of September
30, 2003 and 2002:
Deferred charges and other assets as of September 30, 2003 and 2002 are
comprised of the following accounts.
Other current liabilities as of September 30, 2003 and 2002 are comprised
of the following accounts.
Deferred credits and other liabilities as of September 30, 2003 and 2002
are comprised of the following accounts.
11. EARNINGS PER SHARE
Basic and diluted earnings per share at September 30 are calculated as
follows:
There were approximately 601,500, 1,118,167 and 685,000 out-of-the-money
options excluded from the computation of diluted earnings per share for the
years ended September 30, 2003, 2002 and 2001 as their exercise price is greater
than the average market price of the common stock.
12. INCOME TAXES
The components of income tax expense from continuing operations for 2003,
2002 and 2001 were as follows:
The provision (benefit) for income taxes is included in the consolidated
financial statements as follows:
During 2003, we recorded a cumulative effect of accounting change to
reflect the adoption of EITF 02-03, as described in Note 5. The $5.1 million
benefit on the cumulative charge reflects a federal and state tax benefit of
39.7 percent.
Reconciliations of the provision for income taxes before the cumulative
effect of accounting change computed at the statutory rate to the reported
provisions for income taxes from continuing operations for 2003, 2002 and 2001
are set forth below:
Deferred income taxes reflect the tax effect of differences between the
basis of assets and liabilities for book and tax purposes. The tax effect of
temporary differences that give rise to significant components of the deferred
tax liabilities and deferred tax assets at September 30, 2003 and 2002 are
presented below:
We have tax carryforwards amounting to $29.3 million. The tax carryforwards
include net operating losses for federal and state income tax purposes amounting
to $14.4 million. The federal net operating loss will begin to expire in 2018.
Depending on the jurisdiction in which the net operating loss was generated, the
state net operating losses will begin to expire between 2016 and 2021. Also
included in the tax carryforward is $12.3 million in alternative minimum tax
credits which do not expire. The balance of tax carryforwards relate to federal
tax credits claimed on research and development activities and expire beginning
in 2011.
During fiscal 2003, the Internal Revenue Service initiated a routine
examination of our fiscal 1999, 2000 and 2001 tax returns. We believe all
material tax items have been accrued related to the years under audit.
13. COMMITMENTS AND CONTINGENCIES
On September 23, 1999, a suit was filed in the District Court of Stevens
County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto,
against more than 200 companies in the natural gas industry including us and our
Colorado-Kansas Division. The plaintiffs, who purport to represent a class
consisting of gas producers, royalty owners, overriding royalty owners, working
interest owners and state taxing authorities, allege the defendants have
underpaid royalties on gas taken from wells situated on non-federal and
non-Indian lands throughout the United States and offshore waters predicated
upon allegations that the defendants' gas measurements are simply inaccurate and
that the defendants failed to comply with applicable regulations and industry
standards over the last 25 years. Although the plaintiffs do not specifically
allege an amount of damages, they contend that this suit is brought to recover
billions of dollars in revenues that the defendants have allegedly unlawfully
diverted from the plaintiffs to themselves. On April 10, 2000, this case was
consolidated for pre-trial proceedings with other similar pending litigation in
federal court in Wyoming in which we are also a defendant along with over 200
other defendants in the case of In Re Natural Gas Royalties Qui Tam Litigation.
In January 2001, the federal court elected to remand this case back to the
Kansas state court. A reconsideration of remand was filed, but it was denied.
The state court now has jurisdiction over this proceeding and has issued a
preliminary case management order. On April 10, 2003, the court denied the
plaintiffs' motion to certify this proceeding as a class action, which ruling
was appealed by the plaintiffs. The court did allow the plaintiffs to file an
amended complaint, which is somewhat narrower in scope than the original
complaint. However, we continue to believe that the plaintiffs' claims are still
lacking in merit, and we intend to continue to vigorously defend this action.
While the results of this litigation cannot be predicted with certainty, we
believe the final outcome of such litigation will not have a material adverse
effect on our financial condition, results of operations or net cash flows.
On February 13, 2002, a suit was filed in the 287th District Court of
Parmer County, Texas by Anderson Brothers, a Partnership, against Atmos Energy
Corporation, et al. The plaintiffs' claims arise out of an alleged breach of
contract by us and by a number of our divisions and subsidiaries concerning the
sale of natural gas used in irrigation activities since 1998 and an alleged
violation of the Texas Agricultural Gas Users Act of 1985. The court has ruled
proper venue to be in Parmer County, Texas. We have been responding to numerous
discovery requests from the plaintiffs. We also filed suit in Travis County,
Texas to have the Texas Agricultural Gas Users Act of 1985 declared
unconstitutional. The court denied our motion for summary judgment which we have
appealed. The plaintiffs seek class action status and to recover unspecified
damages plus attorneys' fees. We have denied any liability and intend to
vigorously defend against the plaintiffs' claims. While the results of this
litigation cannot be predicted with certainty, we believe the final outcome of
such litigation will not have a material adverse effect on our financial
condition, results of operations or net cash flows.
We are a plaintiff in a case styled Energas Company, a Division of Atmos
Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK
Westex Transmission, Inc. and ONEOK Energy Marketing and Trading Company II,
filed in December 2001, pending in the District Court of Lubbock County, Texas,
72nd Judicial District. In this case, we are seeking to collect our receivable
related to approximately 5.0 Bcf of natural gas that we believe was not
delivered. Atmos has settled a portion of its claims with the parties and will
continue to pursue recovery of the remaining claims, which we believe are fully
recoverable.
United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a
party to an action filed in June 2000 which is pending in the Circuit Court of
Sevier County, Tennessee. The plaintiffs' claims arise out of injuries alleged
to have been caused by a low-level propane explosion. The plaintiffs seek to
recover damages of $13.0 million. Discovery activities continue in this case. We
have denied any liability, and we intend to vigorously defend against the
plaintiffs' claims. While the results of this litigation cannot be predicted
with certainty, we believe the final outcome of such litigation will not have a
material adverse effect on our financial condition, results of operations or net
cash flows.
We are a party to other litigation and claims that arise in the ordinary
course of our business. While the results of such litigation and claims cannot
be predicted with certainty, we believe the final outcome of such litigation and
claims will not have a material adverse effect on our financial condition,
results of operations or net cash flows.
We are the owner or previous owner of manufactured gas plant sites in
Johnson City and Bristol, Tennessee and Hannibal, Missouri which were used to
supply gas prior to the availability of natural gas. The gas manufacturing
process resulted in certain by-products and residual materials including coal
tar. The manufacturing process used by our predecessors was an acceptable and
satisfactory process at the time such operations were being conducted. Under
current environmental protection laws and regulations, we may be responsible for
response actions with respect to such materials if response actions are
necessary.
United Cities Gas Company and the Tennessee Department of Environment and
Conservation (TDEC) entered into a consent order effective January 23, 1997, to
facilitate the investigation, removal and remediation of the Johnson City site.
Prior to our merger with United Cities Gas Company in July 1997, United Cities
Gas Company began the implementation of the consent order in the first quarter
of 1997 which we have continued through September 30, 2003. The investigative
phase of the work at the site has been completed and an interim removal action
was completed in June 2001. We installed four groundwater monitoring wells at
the site in 2002 and have submitted the analytical results to the TDEC. We have
completed a risk assessment report which is currently under review by the TDEC.
Finally, we have completed a feasibility study for this site that was submitted
in October 2003. The feasibility study recommends a remedial action that will
limit the use of and access to the impacted soil, cap the site with the addition
of a clay fill and geosynthetic liner, and groundwater monitoring for a period
of up to 30 years. The estimated cost of the proposed remedial action is $1.5
million, which is comprised primarily of operating and maintenance costs
associated with a groundwater monitoring project. The Tennessee Regulatory
Authority granted us permission to defer, until our next rate case in Tennessee,
all costs incurred in Tennessee in connection with state and federally mandated
environmental control requirements.
In March 2002, the TDEC contacted us about conducting an investigation at a
former manufactured gas plant located in Bristol, Tennessee. We agreed to
perform a preliminary investigation at the site which was completed in June
2002. The investigation identified manufactured gas plant residual materials in
the soil beneath the site and we have proposed performing a focused removal
action to remove any such residuals. The TDEC has requested that the focused
removal action be conducted pursuant to a voluntary agreement. We are continuing
the process of negotiating the voluntary agreement with TDEC and hope to conduct
the focused removal action later this year.
On July 22, 1998, we entered into an Abatement Order on Consent with the
Missouri Department of Natural Resources addressing the former manufactured gas
plant located in Hannibal, Missouri. We agreed to perform a removal action, a
subsequent site evaluation and to reimburse the response costs incurred by the
state of Missouri in connection with the property. The removal action was
conducted and completed in August 1998, and the site evaluation field work was
conducted in August 1999. A risk assessment for the site has been completed and
is currently under review by the Missouri Department of Natural Resources. In
preparation for the risk assessment, we executed and recorded certain site use
limitations including restricting use of the site to commercial and industrial
purposes and prohibiting the withdrawal of groundwater for use as drinking
water.
In 1995, United Cities Gas Company, entered into an agreement to pay $1.8
million to Union Electric, now Ameren, in exchange for an indemnity covering
United Cities' share of additional investigations and
environmental response actions for soil contamination at a former manufactured
gas plant in Keokuk, Iowa. However, the extent of groundwater contamination at
the site, which is not covered by the indemnity, has yet to be determined.
As of September 30, 2003, we had incurred costs of approximately $1.7
million for the investigations of the Johnson City and Bristol, Tennessee and
Hannibal, Missouri sites and had a remaining accrual relating to these sites of
$0.2 million, which is recorded as a component of other current liabilities.
We have completed investigation and remediation activities pursuant to
Consent Orders between the Kansas Department of Health and Environment (KDHE)
and United Cities Gas Company. The Orders provided for the investigation and
remediation of mercury contamination at gas pipeline sites which utilize or
formerly utilized mercury meter equipment in Kansas. The Final Interim
Characterization and Remediation Report has been submitted to the KDHE. We
amended the Orders with the KDHE to include all mercury meters that belonged to
our Colorado-Kansas Division before the merger with United Cities Gas Company on
July 31, 1997. All work on these sites has been completed. On October 1, 2003,
we received a letter from the KDHE, in which the KDHE stated that upon our
payment to the KDHE of all oversight costs, we will have fulfilled the terms of
the Consent Orders, at which time we will be receiving a termination letter from
the KDHE evidencing such fulfillment. As of September 30, 2003, we had incurred
costs of $0.2 million for these sites and had a remaining accrual of $0.2
million for recovery, which is recorded as a component of other current
liabilities.
We are a party to other environmental matters and claims that arise out of
our ordinary business. While the ultimate results of response actions to these
environmental matters and claims cannot be predicted with certainty, we believe
the final outcome of such response actions will not have a material adverse
effect on our financial condition, results of operations or net cash flows
because we believe that the expenditures related to such response actions will
either be recovered through rates, shared with other parties or are adequately
covered by insurance.
AEM has commitments to purchase physical quantities of natural gas under
contracts indexed to the forward Nymex strip or fixed price contracts. At
September 30, 2003, AEM is committed to purchase 83.1 Bcf within one year and
24.8 Bcf within one to three years under indexed contracts. AEM is committed to
purchase 2.2 Bcf within one year under fixed price contracts with prices ranging
from $3.13 to $6.70. Purchases under these contracts totaled $1,454.8 million,
$725.6 million and $361.4 million for 2003, 2002 and 2001.
Our utility segment maintains supply contracts with several vendors that
generally cover a period of up to one year. Commitments for estimated base gas
volumes are established under these contracts on a monthly basis at
contractually negotiated prices. Commitments for incremental daily purchases are
made as necessary during the month in accordance with the terms of the
individual contract.
The limited partnership agreement of U.S. Propane, L.P., an entity in which
we own an approximate 19 percent membership interest, requires that in the event
of liquidation, all limited partners would be required to restore capital
account deficiencies, including any unsatisfied obligations of the partnership.
Under the agreement, our maximum capital account restoration is $4.7 million. As
of September 30, 2003, our capital account was positive.
14. LEASES
Atmos Power Systems, Inc. constructs and operates electric peaking power
generating plants and associated facilities and may enter into agreements to
either lease or sell these plants. We completed a sales-type lease transaction
for one distributed electric generation plant in 2001 and a second sales-type
lease transaction in 2003. In 2001, we recognized a gain of $0.8 million and
deferred $4.7 million of income, which will be recognized using the interest
method through August 2011. In 2003, we recognized a gain of $3.9 million and
deferred $8.6 million in income, which will be recognized using the interest
method through September 2012. As of September 30, 2003 and 2002, we recorded
receivables of $28.4 million and $9.8 million and recorded income of $2.0
million, $0.7 million and $0.2 million for fiscal years 2003, 2002 and 2001. The
future minimum lease payments to be received for each of the five succeeding
years are as follows:
We have entered into non-cancelable operating leases for office and
warehouse space used in our operations. The remaining lease terms range from one
to 15 years and generally provide for the payment of taxes, insurance and
maintenance by the lessee. Renewal options exist for certain of these leases. We
have also entered into capital leases for division offices and operating
facilities. Property, plant and equipment included amounts for capital leases of
$5.2 million at September 30, 2003 and 2002. Accumulated depreciation for these
capital leases totaled $2.2 million at September 30, 2003 and 2002. Depreciation
expense for these assets is included in consolidated depreciation expense on the
consolidated statement of income.
The related future minimum lease payments at September 30, 2003 were as
follows:
Consolidated lease and rental expense amounted to $8.9 million, $8.1
million and $5.9 million for fiscal 2003, 2002 and 2001.
15. CONCENTRATION OF CREDIT RISK
Credit risk is the risk of financial loss to us if counterparties fail to
perform their contractual obligations. We engage in transactions for the
purchase and sale of products and services with major companies in the energy
industry and with commercial, residential and municipal energy consumers. These
transactions principally occur in the South and Midwest regions of the United
States. We believe that this geographic concentration does not contribute
significantly to our overall exposure to credit risk. Credit risk associated
with trade accounts receivable is limited due to the large number of customers.
We maintain credit policies with respect to our counterparties that we
believe minimize overall credit risk. Where appropriate, such policies include
the evaluation of a prospective counterparty's financial condition, collateral
requirements and the use of standardized agreements that facilitate the netting
of cash flows associated with a single counterparty. We also monitor the
financial condition of existing counterparties on an ongoing basis. We maintain
a provision for credit losses based upon factors surrounding the credit risk of
customers, historical trends and other information. We believe, based on our
credit policies and our provisions for credit losses, that our financial
position, results of operations and cash flows will not be materially affected
as a result of counterparty nonperformance.
The following table presents our credit exposure by operating segment based
upon the unrealized fair value of our derivative contracts that represent assets
as of September 30, 2003. Investment grade counterparties have minimum credit
ratings of BBB assigned by Standard & Poor's Rating Group or Baa3 assigned by
Moody's Investor Service. Non-investment grade counterparties are comprised of
counterparties that are below investment grade or are counterparties that have
not been assigned an internal investment grade rating due to the short-term
nature of the contracts associated with that counterparty. This category is
comprised of numerous smaller counterparties, none of which is individually
significant.
(1) Counterparty risk for our utility segment is minimized because hedging gains
and losses are passed through to our customers.
Because AEM's operations are concentrated in the natural gas industry, its
customers and suppliers may be subject to economic risks affecting that
industry. Additionally, AEM's credit risk has increased due to higher natural
gas prices as compared with the prior year. However, this risk is somewhat
mitigated because a larger percentage of AEM's business in the current year is
with municipal customers, who typically are rated investment grade, as compared
with the prior year.
16. SUPPLEMENTAL CASH FLOW DISCLOSURES
Supplemental disclosures of cash flow information for 2003, 2002 and 2001
are presented below.
In December 2002, we partially funded the acquisition of MVG through the
issuance of $74.7 million in Atmos Energy common stock consisting of 3,386,287
unregistered shares.
In June 2003, we contributed to the Atmos Energy Corporation Master
Retirement Trust for the benefit of the Atmos Pension Account Plan 1,169,700
shares of Atmos restricted common stock with a value of $28.8 million.
In April 2001, we completed the acquisition of the remaining 55 percent of
Woodward Marketing, L.L.C that we did not already own in exchange for 1,423,193
restricted shares of our common stock with a value of $26.7 million.
17. SEGMENT INFORMATION
Atmos Energy Corporation and its subsidiaries are engaged primarily in the
natural gas utility business as well as certain 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 12 states. 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
distribution companies located 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 Kansas, Kentucky, Louisiana and Mississippi. We market natural gas
to industrial customers primarily in West Texas and 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 regulated 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 all of our other
non-utility operations.
Our determination of reportable segments considers the strategic operating
units under which we manage sales of various products and services to customers
in differing regulatory environments. The accounting policies of the segments
are the same as those described in the summary of significant accounting
policies. We
evaluate performance based on net income or loss of the respective operating
units. Summarized income statements and capital expenditures by segment are
shown in the following tables.
The following table summarizes our revenues by products and services for
the year ended September 30.
Balance sheet information at September 30, 2003 and 2002 by segment is
presented in the following tables:
18. RELATED PARTY TRANSACTIONS
AEM provides a variety of natural gas management services to our
Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions including
furnishing natural gas supplies at fixed and market-based prices and the
management of certain of our underground storage facilities. Additionally, at
times, AEM places financial instruments for our various divisions to protect us
and our customers from unusually large winter period gas price increases. The
following summarizes these transactions with AEM.
(1) Gas purchases are made in a competitive bidding process, reflect market
prices and exclude demand and other charges.
JD Woodward became Senior Vice President, Non-Utility Operations of the
Company on April 1, 2001. Woodward Marketing L.L.C., a wholly-owned subsidiary
of the Company through September 30, 2003 and its successor, AEM (see Note 1),
leases office space from one corporation owned by Mr. Woodward. The lease
originated in April 2002 and expires in March 2007. Base lease payments are
$225,000 in the first year of the lease and increase to $253,000 in the final
year.
During 2003 and 2002, our utility division leased office space and vehicles
from our natural gas marketing and other non-utility segments. Base lease
payments were $0.7 million in 2003 and 2002. There were no such leasing
activities during 2001.
Effective in October 1994, Charles Vaughan retired as an officer and
employee of the Company and entered into a consulting agreement with the
Company. Under the terms of the agreement, Mr. Vaughan performed such consulting
services as the Board requested from time to time. During fiscal 2002, Mr.
Vaughan received $130,000 in payment for his services during that period. In
addition, pursuant to the terms of the agreement, upon early termination of the
agreement by the Company in September 2002, Mr. Vaughan received a total of
$175,000, representing the total sums due him under the remainder of the
agreement that was due to expire September 30, 2004.
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized unaudited quarterly financial data is presented below. The sum
of net income per share by quarter may not equal the net income per share for
the year due to variations in the weighted average shares outstanding used in
computing such amounts. Our businesses are seasonal due to weather conditions in
our service areas. For further information on its effects on quarterly results,
see the "Results of Operations" discussion included in the "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
section herein.
As more fully described in Note 5, upon the adoption of EITF 02-03, our
inventory, storage, transportation and index-priced physical forward contracts
are no longer marked to market. Our index-priced physical forward contracts are
now considered normal purchases and sales under SFAS 133. In conjunction with
the adoption of EITF 02-03, energy trading contracts resulting in delivery of a
commodity where we are
the principal in the transaction are included as natural gas marketing sales or
purchases. The following selected quarterly financial data has been reclassified
to conform with this new presentation.
None.
As of the end of the period covered by this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including the Chairman, President and Chief Executive Officer and Senior Vice
President and Chief Financial Officer, of the effectiveness of our disclosure
controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that
evaluation, the Chairman, President and Chief Executive Officer, and Senior Vice
President and Chief Financial Officer have concluded that our disclosure
controls and procedures continue to be effective.
Such disclosure controls and procedures are controls and procedures
designed to ensure that all information required to be disclosed in our reports
filed under the Exchange Act is recorded, processed, summarized and reported
within the time periods set forth in applicable Securities and Exchange
Commission forms, rules and regulations. In addition, we have reviewed our
internal control over financial reporting and have concluded that there has been
no change in such internal control during the fourth quarter of fiscal 2003 that
has materially affected or is reasonably likely to materially affect the
Company's internal control over financial reporting.
Information regarding directors and compliance with Section 16(a) of the
Securities Exchange Act of 1934 is incorporated herein by reference from the
Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on
February 11, 2004. Information regarding executive officers is included in Part
I of this Form 10-K.
Identification of the members of the Audit Committee of the Board of
Directors as well as the Board of Directors' determination as to whether one or
more audit committee financial experts is serving on the Audit Committee of the
Board of Directors is incorporated herein by reference from the Company's
Definitive Proxy Statement for the Annual Meeting of Shareholders on February
11, 2004.
The Company has adopted a code of ethics for its principal executive
officer and senior financial officers. Such code of ethics is represented by the
Company's Code of Conduct, which is applicable to all directors, officers and
employees of the Company, including the Company's principal executive officer
and senior financial officers. A copy of the Company's Code of Conduct is posted
on the Company's website under "Corporate Governance".
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 11, 2004.
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 11, 2004.
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 11, 2004.
Incorporated herein by reference from the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders on February 11, 2004.
(a) 1. and 2. Financial statements and financial statement schedules.
The financial statements and financial statement schedule listed in the
Index to Financial Statements in Item 8 are filed as part of this Form 10-K.
3. Exhibits
The exhibits listed in the accompanying Exhibits Index are filed as part of
this Form 10-K. The exhibits numbered 10.15(a) through 10.26(b) are management
contracts or compensatory plans or arrangements.
(b) Reports on Form 8-K
None.
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Date: November 21, 2003
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below hereby constitutes and appoints Robert W. Best and John P. Reddy, or
either of them acting alone or together, as his true and lawful attorney-in-fact
and agent with full power to act alone, for him and in his name, place and
stead, in any and all capacities, to sign any and all amendments to this Form
10-K, and to file the same, with all exhibits thereto, and all other documents
in connection therewith, with the Securities and Exchange Commission, granting
unto said attorney-in-fact and agent full power and authority to do and perform
each and every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he might or could do in
person, hereby ratifying and confirming all that said attorney-in-fact and
agent, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated:
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.
Tennessee................................................... November -- April
Georgia..................................................... October -- May
Mississippi................................................. November -- May
Kentucky.................................................... November -- April
Kansas(1)................................................... October -- May
Amarillo, Texas(1).......................................... October -- May
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.
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.
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.
OPERATING STATISTICS
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
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
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
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
REGULATION
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%
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)
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 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.
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.
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
========== ========== ========== =======
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
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
========== =======
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
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
===== =====
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
========= ====== =========
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%
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
========== ========== ======= ========= ==========
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.
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.
HIGHLIGHTS
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.
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.
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.
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
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 $ 37,556 $ 1,592
Intersegment activity................................ 607 834 587
-------- -------- --------
Natural gas marketing segment contribution to
consolidated gross profit.......................... $ 24,772 $ 38,390 $ 2,179
======== ======== ========
Other non-utility segment gross profit............... $ 20,090 $ 16,683 $ 10,831
Intersegment activity................................ (9,018) (10,314) (3,266)
-------- -------- --------
Other non-utility segment contribution to
consolidated gross profit.......................... $ 11,072 $ 6,369 $ 7,565
======== ======== ========
Utility segment throughput -- MMcf................... 254,671 214,133 218,619
Intersegment activity -- MMcf........................ (6,706) (5,592) (845)
-------- -------- --------
Consolidated utility segment throughput -- MMcf...... 247,965 208,541 217,774
======== ======== ========
Natural gas marketing segment throughput -- MMcf..... 294,785 273,692 98,869
Intersegment activity -- MMcf........................ (68,824) (69,665) (43,400)
-------- -------- --------
Consolidated natural gas marketing segment
throughput -- MMcf................................. 225,961 204,027 55,469
======== ======== ========
Natural gas marketing segment
Other income (expense) -- Other income for the year ended September 30,
2003 was $2.2 million, compared with an expense of $1.3 million for the year
ended September 30, 2002. The $3.5 million change was primarily attributable to
a $3.9 million gain associated with a sales-type lease of a distributed electric
generation plant which was recognized in the first quarter of 2003 and improved
earnings from our indirect investment in Heritage Propane L.P., partially offset
by a $0.6 million charge associated with the cancellation of our weather
insurance policy during the third quarter of fiscal 2003.
SEPTEMBER 30
---------------------------------------
2003 2002
------------------ ------------------
(IN THOUSANDS, EXCEPT PERCENTAGES)
Short-term debt............................... $ 118,595 6.4% $ 145,791 10.3%
Long-term debt................................ 873,263 47.2% 692,443 49.1%
Shareholders' equity.......................... 857,517 46.4% 573,235 40.6%
---------- ----- ---------- -----
Total capitalization, including short-term
debt........................................ $1,849,375 100.0% $1,411,469 100.0%
========== ===== ========== =====
CASH FLOWS
For the year ended September 30, 2003, we invested $233.4 million compared
with $158.2 million for the year ended September 30, 2002 and $468.1 million for
the year ended September 30, 2001. Capital expenditures were $159.4 million
during the year ended September 30, 2003 compared to $132.3 million for the year
ended September 30, 2002 and $113.1 million for the year ended September 30,
2001. Capital projects for fiscal years 2003, 2002 and 2001 include expenditures
for additional mains, services, meters and equipment to grow our customer base.
Additionally, capital expenditures for 2003 include approximately $14.0 million
for Mississippi Valley Gas Company Division capital expenditures. Fiscal 2002
and 2001 cash flows from investing activities also included $8.5 million and
$5.4 million for the acquisition of assets to be leased to third parties.
Finally, fiscal 2001 cash flows from investing activities included cash receipts
of $6.6 million related to the sale of certain utility assets.
- During fiscal 2003, we paid $55.3 million in cash dividends compared with
dividend payments of $48.6 million and $44.1 million for fiscal 2002 and
2001. The increase in dividends paid over the preceding two years
reflects increases in the quarterly dividend rate and the number of
shares outstanding.
FOR THE YEAR ENDED SEPTEMBER 30
-------------------------------
2003 2002 2001
--------- ------- ---------
Shares issued:
Direct stock purchase plan......................... 585,743 505,202 411,159
Retirement savings plan............................ 360,725 326,335 225,945
Long-term incentive plan........................... 181,429 50,465 17,172
Long-term stock plan for Mid-States Division....... 13,000 -- 15,300
Outside directors stock-for-fee plan............... 2,969 2,429 2,152
Non-employee directors equity incentive
compensation plan............................... -- -- 2,740
Acquisition of Woodward Marketing L.L.C. .......... -- -- 1,423,193
December 2000 Equity Offering...................... -- -- 6,741,500
Acquisition of MVG................................. 3,386,287 -- --
Pension account plan funding....................... 1,169,700 -- --
2003 Offering...................................... 4,100,000 -- --
--------- ------- ---------
Total shares issued............................. 9,799,853 884,431 8,839,161
========= ======= =========
serves as a backup liquidity facility for our commercial paper program. This
facility was renewed in July 2003 with a $50.0 million increase in the amount of
the facility under substantially the same terms as those of the prior facility.
This facility will expire in July 2004. At September 30, 2003, $118.6 million of
commercial paper was outstanding, and Atmos Energy Corporation letters of credit
reduced the amount available by an additional $2.4 million. We have a second
unsecured facility in place for $18.0 million that bears interest at the Fed
Funds rate plus 0.5 percent. At September 30, 2003, there were no borrowings
under this credit facility. These credit facilities are negotiated at least
annually and are used for working capital purposes.
1.25 percent through July 2003 when the interest rate was increased to LIBOR
plus 2.75 percent. Any outstanding amounts under this facility are subordinated
to Woodward Marketing's $210.0 million uncommitted demand credit facility
described above. At September 30, 2003, $70.0 million was outstanding under this
facility.
Our debt is rated by three rating agencies: Standard & Poor's Corporation
(S&P), Moody's Investors Service (Moody's) and Fitch Ratings, Inc. (Fitch). Our
current debt ratings are as follows:
S&P MOODY'S FITCH
--- ------- -----
Long-term debt.............................................. A- A3 A-
Commercial paper............................................ A-2 P-2 F-2
PAYMENTS DUE BY PERIOD
-------------------------------------------------------
LESS THAN AFTER
TOTAL 1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS
-------- --------- --------- --------- --------
(IN THOUSANDS)
CONTRACTUAL OBLIGATIONS
Long-Term Debt.................... $873,263 $ 9,345 $11,078 $12,506 $840,334
Capital Lease Obligations......... 5,125 876 1,276 795 2,178
Operating Leases.................. 58,925 10,331 18,821 12,956 16,817
-------- -------- ------- ------- --------
Total Contractual Obligations... $937,313 $ 20,552 $31,175 $26,257 $859,329
======== ======== ======= ======= ========
OTHER COMMERCIAL COMMITMENTS
Lines of Credit................... $118,595 $118,595 $ -- $ -- $ --
======== ======== ======= ======= ========
Our utility segment maintains supply contracts with several vendors that
generally cover a period of up to one year. Commitments for estimated base gas
volumes are established under these contracts on a monthly basis at
contractually negotiated prices. Commitments for incremental daily purchases are
made as necessary during the month in accordance with the terms of the
individual contract.
2003 2002 2001
---- ---- -----
Discount rate............................................... 6.00% 7.25% 7.50%
Rate of compensation increase............................... 4.00% 4.00% 4.00%
Expected return on plan assets.............................. 9.00% 9.25% 10.00%
NATURAL GAS
UTILITY MARKETING TOTAL
------- ----------- --------
(IN THOUSANDS)
Assets from risk management activities, current...... $ 202 $ 22,057 $ 22,259
Assets from risk management activities, noncurrent... -- 1,699 1,699
Liabilities from risk management activities,
current............................................ (7,941) (12,849) (20,790)
Liabilities from risk management activities,
noncurrent......................................... -- (763) (763)
------- -------- --------
Net assets (liabilities)............................. $(7,739) $ 10,144 $ 2,405
======= ======== ========
cumulative effect of accounting change of $7.8 million, net of income tax
benefit, upon the adoption of EITF 02-03 in the second quarter of fiscal 2003.
Fixed price contracts generally continue to be marked to market. In conjunction
with the adoption of EITF 02-03, energy trading contracts resulting in delivery
of a commodity where we are the principal in the transaction are included as
natural gas marketing sales or purchases at the time of delivery.
NATURAL GAS
UTILITY MARKETING
------- -----------
Fair value of contracts at September 30, 2002............... $ 4,424 $ 6,651
Contracts realized/settled................................ (4,638) (1,363)
Fair value of new contracts............................... (7,525) 6,176
Other changes in value.................................... -- 7,479
Cumulative effect of accounting change.................... -- (8,799)
------- -------
Fair value of contracts at September 30, 2003............... $(7,739) $10,144
======= =======
FAIR VALUE OF CONTRACTS AT SEPTEMBER 30, 2003
-------------------------------------------------
MATURITY IN YEARS
------------------------------------
GREATER TOTAL FAIR
SOURCE OF FAIR VALUE LESS THAN 1 1-3 4-5 THAN 5 VALUE
-------------------- ----------- ------ --- ------- ----------
(IN THOUSANDS)
Prices actively quoted................... $(4,420) $ 107 $-- $-- $(4,313)
Prices provided by other external
sources................................ 6,793 1,346 88 -- 8,227
Prices based on models and other
valuation methods...................... (904) (605) -- -- (1,509)
------- ------ --- -- -------
Total Fair Value......................... $ 1,469 $ 848 $88 $-- $ 2,405
======= ====== === == =======
liabilities and equity. Under SFAS 150, mandatorily redeemable financial
instruments, obligations to repurchase the issuer's shares by transferring
assets and certain obligations to issue a variable number of shares to settle
that obligation, must be classified as liabilities on the balance sheet and
initially recorded at fair value. SFAS 150 is effective for the Company for
financial instruments entered into or modified after May 31, 2003, and on July
1, 2003 for most previously existing financial instruments. In November 2003,
the FASB voted to defer indefinitely the effective date for certain mandatorily
redeemable non-controlling interests (MRNI) associated with finite-lived
subsidiaries. For all other MRNIs, the effective date was deferred to November
5, 2003. The adoption of SFAS 150 did not impact our financial position, results
of operations or net cash flows as we currently do not use any of the financial
instruments subject to this statement.
not, however, consider the effects that such adverse changes may have on overall
economic activity nor do they consider additional actions we may take to
mitigate exposure to such changes. Actual results may differ.
Counterparty risk is the risk of loss from nonperformance by financial
counterparties to a contract. Financial instruments, which subject AEM to
counterparty risk, consist primarily of financial instruments arising from
trading and risk management activities and overnight repurchase agreements that
are not insured. Exchange traded future and option contracts are generally
guaranteed by the exchanges.
PAGE
----
Report of independent auditors.............................. 47
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2003 and
2002................................................... 48
Consolidated statements of income for the years ended
September 30, 2003, 2002 and 2001...................... 49
Consolidated statements of shareholders' equity for the
years ended September 30, 2003, 2002 and 2001.......... 50
Consolidated statements of cash flows for the years ended
September 30, 2003, 2002 and 2001...................... 51
Notes to consolidated financial statements................ 52
Selected Quarterly Financial Data (unaudited)............. 95
Financial statement schedule for the years ended September
30, 2003, 2002 and 2001
II. Valuation and Qualifying Accounts..................... 101
Atmos Energy Corporation
November 10, 2003
SEPTEMBER 30
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS,
EXCEPT SHARE DATA)
ASSETS
Property, plant and equipment............................... $2,463,992 $2,103,428
Construction in progress.................................... 16,147 24,399
---------- ----------
2,480,139 2,127,827
Less accumulated depreciation and amortization.............. 964,150 827,507
---------- ----------
Net property, plant and equipment......................... 1,515,989 1,300,320
Current assets
Cash and cash equivalents................................. 15,683 47,991
Cash held on deposit in margin account.................... 17,903 10,192
Accounts receivable, less allowance for doubtful accounts
of $13,051 in 2003 and $10,509 in 2002................. 216,783 136,227
Gas stored underground.................................... 168,765 91,783
Other current assets...................................... 38,863 44,962
---------- ----------
Total current assets................................... 457,997 331,155
Goodwill and intangible assets.............................. 273,499 190,380
Deferred charges and other assets........................... 271,023 159,530
---------- ----------
$2,518,508 $1,981,385
========== ==========
CAPITALIZATION AND LIABILITIES
Shareholders' equity
Common stock, no par value (stated at $.005 per share);
100,000,000 shares authorized; issued and outstanding:
2003 -- 51,475,785 shares, 2002 -- 41,675,932 shares... $ 257 $ 208
Additional paid-in capital................................ 736,180 508,265
Retained earnings......................................... 122,539 106,142
Accumulated other comprehensive loss...................... (1,459) (41,380)
---------- ----------
Shareholders' equity................................... 857,517 573,235
Long-term debt.............................................. 863,918 670,463
---------- ----------
Total capitalization................................... 1,721,435 1,243,698
Commitments and Contingencies (Note 13)
Current liabilities
Accounts payable and accrued liabilities.................. 179,852 136,773
Other current liabilities................................. 127,923 159,727
Short-term debt........................................... 118,595 145,791
Current maturities of long-term debt...................... 9,345 21,980
---------- ----------
Total current liabilities.............................. 435,715 464,271
Deferred income taxes....................................... 223,350 134,540
Deferred credits and other liabilities...................... 138,008 138,876
---------- ----------
$2,518,508 $1,981,385
========== ==========
YEAR ENDED SEPTEMBER 30
---------------------------------------
2003 2002 2001
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Operating revenues
Utility segment........................................ $1,554,082 $ 937,526 $1,380,148
Natural gas marketing segment.......................... 1,668,493 1,031,874 447,096
Other non-utility segment.............................. 21,630 24,705 59,436
Intersegment eliminations.............................. (444,289) (343,141) (161,199)
---------- ---------- ----------
2,799,916 1,650,964 1,725,481
Purchased gas cost
Utility segment........................................ 1,062,679 559,891 1,017,363
Natural gas marketing segment.......................... 1,644,328 994,318 445,504
Other non-utility segment.............................. 1,540 8,022 48,605
Intersegment eliminations.............................. (443,607) (342,407) (161,199)
---------- ---------- ----------
2,264,940 1,219,824 1,350,273
---------- ---------- ----------
Gross profit........................................... 534,976 431,140 375,208
Operating expenses
Operation and maintenance.............................. 205,090 158,119 139,608
Depreciation and amortization.......................... 87,001 81,469 67,664
Taxes, other than income............................... 55,045 36,221 37,655
---------- ---------- ----------
Total operating expenses............................ 347,136 275,809 244,927
---------- ---------- ----------
Operating income......................................... 187,840 155,331 130,281
Other income (expense)
Equity in earnings of Woodward Marketing, L.L.C. ...... -- -- 8,062
Miscellaneous income (expense)......................... 2,191 (1,321) (1,874)
---------- ---------- ----------
Total 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
Income tax expense....................................... 46,910 35,180 33,368
---------- ---------- ----------
Income before cumulative effect of accounting change..... 79,461 59,656 56,090
Cumulative effect of accounting change, net of income tax
benefit................................................ (7,773) -- --
---------- ---------- ----------
Net income.......................................... $ 71,688 $ 59,656 $ 56,090
========== ========== ==========
Per share data
Basic income per share:
Income before cumulative effect of accounting
change............................................ $ 1.72 $ 1.45 $ 1.47
Cumulative effect of accounting change, net of
income tax benefit................................ (.17) -- --
---------- ---------- ----------
Net income.......................................... $ 1.55 $ 1.45 $ 1.47
========== ========== ==========
Diluted income per share:
Income before cumulative effect of accounting
change............................................ $ 1.71 $ 1.45 $ 1.47
Cumulative effect of accounting change, net of
income tax benefit................................ (.17) -- --
---------- ---------- ----------
Net income.......................................... $ 1.54 $ 1.45 $ 1.47
========== ========== ==========
Weighted average shares outstanding:
Basic.................................................. 46,319 41,171 38,156
========== ========== ==========
Diluted................................................ 46,496 41,250 38,247
========== ========== ==========
ACCUMULATED
COMMON STOCK OTHER
------------------- ADDITIONAL COMPREHENSIVE
NUMBER OF STATED PAID-IN INCOME RETAINED
SHARES VALUE CAPITAL (LOSS) EARNINGS TOTAL
---------- ------ ---------- ------------- -------- --------
(IN THOUSANDS, EXCEPT SHARE DATA)
BALANCE, SEPTEMBER 30, 2000.......... 31,952,340 $160 $306,887 $ 2,265 $ 83,154 $392,466
COMPREHENSIVE INCOME:
Net income......................... -- -- -- -- 56,090 56,090
Unrealized holding losses on
investments, net................. -- -- -- (3,685) -- (3,685)
--------
TOTAL COMPREHENSIVE INCOME....... 52,405
CASH DIVIDENDS ($1.16 PER SHARE)..... -- -- -- -- (44,112) (44,112)
COMMON STOCK ISSUED:
Public offering.................... 6,741,500 34 142,009 -- -- 142,043
Acquisition of Woodward Marketing,
L.L.C............................ 1,423,193 7 26,650 -- -- 26,657
Direct stock purchase plan......... 411,159 2 8,682 -- -- 8,684
Retirement savings plan............ 225,945 1 5,098 -- -- 5,099
Long-term incentive plan........... 17,172 -- 272 -- -- 272
United Cities long-term stock
plan............................. 15,300 -- 240 -- -- 240
Non-employee directors equity
incentive compensation plan...... 2,740 -- 60 -- -- 60
Outside directors stock-for-fee
plan............................. 2,152 -- 50 -- -- 50
---------- ---- -------- -------- -------- --------
BALANCE, SEPTEMBER 30, 2001.......... 40,791,501 204 489,948 (1,420) 95,132 583,864
COMPREHENSIVE INCOME:
Net income......................... -- -- -- -- 59,656 59,656
Minimum pension liability, net..... -- -- -- (39,432) -- (39,432)
Unrealized holding losses on
investments, net................. -- -- -- (528) -- (528)
--------
TOTAL COMPREHENSIVE INCOME....... 19,696
CASH DIVIDENDS ($1.18 PER SHARE)..... -- -- -- -- (48,646) (48,646)
COMMON STOCK ISSUED:
Direct stock purchase plan......... 505,202 2 10,546 -- -- 10,548
Retirement savings plan............ 326,335 2 7,137 -- -- 7,139
Long-term incentive plan........... 50,465 -- 579 -- -- 579
Outside directors stock-for-fee
plan............................. 2,429 -- 55 -- -- 55
---------- ---- -------- -------- -------- --------
BALANCE, SEPTEMBER 30, 2002.......... 41,675,932 208 508,265 (41,380) 106,142 573,235
COMPREHENSIVE INCOME:
Net income......................... -- -- -- -- 71,688 71,688
Minimum pension liability, net..... -- -- -- 39,432 -- 39,432
Unrealized holding gains on
investments, net................. -- -- -- 489 -- 489
--------
TOTAL COMPREHENSIVE INCOME....... 111,609
CASH DIVIDENDS ($1.20 PER SHARE)..... -- -- -- -- (55,291) (55,291)
COMMON STOCK ISSUED:
Public offering.................... 4,100,000 20 99,102 -- -- 99,122
Acquisition of Mississippi Valley
Gas Company...................... 3,386,287 17 74,633 -- -- 74,650
Contribution to Atmos Pension
Account Plan..................... 1,169,700 6 28,757 -- -- 28,763
Direct stock purchase plan......... 585,743 3 13,209 -- -- 13,212
Retirement savings plan............ 360,725 2 8,277 -- -- 8,279
Long-term incentive plan........... 181,429 1 3,664 -- -- 3,665
Long-term stock plan for Mid-States
Division......................... 13,000 -- 206 -- -- 206
Outside directors stock-for-fee
plan............................. 2,969 -- 67 -- -- 67
---------- ---- -------- -------- -------- --------
BALANCE, SEPTEMBER 30, 2003.......... 51,475,785 $257 $736,180 $ (1,459) $122,539 $857,517
========== ==== ======== ======== ======== ========
YEAR ENDED SEPTEMBER 30
---------------------------------
2003 2002 2001
--------- --------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.............................................. $ 71,688 $ 59,656 $ 56,090
Adjustments to reconcile net income to net cash provided
by operating activities:
Cumulative effect of accounting change, net of income
tax benefit........................................ 7,773 -- --
Depreciation and amortization:
Charged to depreciation and amortization........... 87,001 81,469 67,664
Charged to other accounts.......................... 2,193 2,452 2,806
Deferred income taxes................................ 53,867 14,509 18,501
Other................................................ (5,885) (3,371) (979)
Changes in assets and liabilities:
(Increase) decrease in cash held on deposit in margin
account............................................ (7,711) 56,474 (62,181)
(Increase) decrease in accounts receivable........... (60,026) (12,181) 65,032
Increase in gas stored underground................... (64,875) (2,228) (3,376)
(Increase) decrease in other current assets.......... (15,747) 28,146 23,049
(Increase) decrease in deferred charges and other
assets............................................. 21,258 (33,515) (12,143)
Increase (decrease) in accounts payable and accrued
liabilities........................................ 19,417 52,302 (94,769)
Increase (decrease) in other current liabilities..... (40,636) 34,195 15,888
Increase (decrease) in deferred credits and other
liabilities........................................ (18,866) 19,487 7,413
--------- --------- ---------
Net cash provided by operating activities.......... 49,451 297,395 82,995
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures.................................... (159,439) (132,252) (113,109)
Acquisitions, net of cash received...................... (74,650) (15,747) (354,755)
Retirements of property, plant and equipment, net....... 704 (1,725) (1,460)
Assets for leasing activities........................... -- (8,511) (5,377)
Proceeds from sale of assets, net....................... -- -- 6,625
--------- --------- ---------
Net cash used in investing activities.............. (233,385) (158,235) (468,076)
CASH FLOWS FROM FINANCING ACTIVITIES
Net decrease in short-term debt......................... (27,196) (55,456) (48,800)
Net proceeds from issuance of long-term debt............ 253,267 -- 347,099
Proceeds from Bridge loan............................... 147,000 -- --
Repayment of Bridge loan................................ (147,000) -- --
Repayment of long-term debt............................. (73,165) (20,651) (17,670)
Repayment of Mississippi Valley Gas debt................ (70,938) -- --
Cash dividends paid..................................... (55,291) (48,646) (44,112)
Issuance of common stock................................ 25,720 18,321 14,405
Net proceeds from equity offering....................... 99,229 -- 142,043
--------- --------- ---------
Net cash provided (used) by financing activities... 151,626 (106,432) 392,965
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents...... (32,308) 32,728 7,884
Cash and cash equivalents at beginning of year............ 47,991 15,263 7,379
--------- --------- ---------
Cash and cash equivalents at end of year.................. $ 15,683 $ 47,991 $ 15,263
========= ========= =========
DIVISION SERVICE AREA
-------- ------------
Atmos Energy Colorado-Kansas Division Colorado, Kansas, Missouri
Atmos Energy Kentucky Division Kentucky
Atmos Energy Louisiana Division Louisiana
Atmos Energy Mid-States Division Georgia, Illinois, Iowa, Missouri, Tennessee,
Virginia
Atmos Energy Texas Division Texas
Mississippi Valley Gas Company Division(1) Mississippi
SEPTEMBER 30
-----------------
2003 2002
------- -------
(IN THOUSANDS)
REGULATORY ASSETS:
Merger and integration costs, net......................... $23,380 $27,066
Deferred MVG operating expenses........................... 4,645 --
Environmental costs....................................... 4,057 3,754
Other..................................................... 2,509 4,878
------- -------
$34,591 $35,698
======= =======
REGULATORY LIABILITIES:
Deferred income taxes, net................................ $ 1,883 $ 1,826
2003....................... 3.8%
2002....................... 3.8%
2001....................... 3.7%
YEAR ENDED SEPTEMBER 30
---------------------------------------
2003 2002 2001
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income -- as reported................................. $71,688 $59,656 $56,090
Restricted stock compensation expense included in income,
net of tax.............................................. 370 487 708
Total stock-based employee compensation expense determined
under fair value based method for all awards, net of
taxes................................................... (1,362) (974) (1,095)
------- ------- -------
Net income -- pro forma................................... $70,696 $59,169 $55,703
======= ======= =======
Earnings per share:
Basic earnings per share -- as reported................. $ 1.55 $ 1.45 $ 1.47
======= ======= =======
Basic earnings per share -- pro forma................... $ 1.53 $ 1.44 $ 1.46
======= ======= =======
Diluted earnings per share -- as reported............... $ 1.54 $ 1.45 $ 1.47
======= ======= =======
Diluted earnings per share -- pro forma................. $ 1.52 $ 1.43 $ 1.46
======= ======= =======
Net property, plant and equipment........................... $156,516
Current assets.............................................. 42,576
Rights-of-way............................................... 11,746
Goodwill.................................................... 81,550
Deferred charges and other assets........................... 9,642
--------
Total assets acquired..................................... 302,030
Current liabilities......................................... (47,750)
Noncurrent liabilities...................................... (81,753)
Other acquisition related costs............................. (23,227)
--------
Purchase price............................................ $149,300
========
SEPTEMBER 30
-----------------------
2003 2002
---------- ----------
(UNAUDITED)
(IN THOUSANDS)
Operating revenue........................................... $2,835,673 $1,870,090
Income before cumulative effect of accounting change........ 76,293 69,295
Net income.................................................. 68,520 69,295
Income before cumulative effect of accounting change per
diluted share............................................. $ 1.62 $ 1.55
Net income per diluted share................................ $ 1.46 $ 1.55
SEPTEMBER 30
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
Goodwill.................................................... $268,469 $185,015
Intangible assets........................................... 5,030 5,365
-------- --------
Total....................................................... $273,499 $190,380
======== ========
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY
SEGMENT SEGMENT SEGMENT TOTAL
-------- ----------- ----------- --------
(IN THOUSANDS)
Balance as of September 30, 2002......... $150,287 $21,288 $13,440 $185,015
Acquisition of MVG (See Note 3).......... 81,550 -- -- 81,550
Deferred tax adjustments and
reclassifications...................... 1,904 1,312 (1,312) 1,904
-------- ------- ------- --------
Balance as of September 30, 2003......... $233,741 $22,600 $12,128 $268,469
======== ======= ======= ========
SEPTEMBER 30, 2003 SEPTEMBER 30, 2002
-------------------------------- --------------------------------
USEFUL GROSS GROSS
LIFE CARRYING ACCUMULATED CARRYING ACCUMULATED
(YEARS) AMOUNT AMORTIZATION NET AMOUNT AMORTIZATION NET
------- -------- ------------ ------ -------- ------------ ------
(IN THOUSANDS)
Customer contracts............... 10 $6,521 $(1,574) $4,947 $6,521 $(1,323) $5,198
Noncompete agreements............ 3 250 (167) 83 250 (83) 167
------ ------- ------ ------ ------- ------
$6,771 $(1,741) $5,030 $6,771 $(1,406) $5,365
====== ======= ====== ====== ======= ======
AMORTIZATION EXPENSE (IN THOUSANDS):
Actual for the fiscal year ending September 30, 2003........ $335
Estimated for the fiscal year ending:
September 30, 2004........................................ 870
September 30, 2005........................................ 652
September 30, 2006........................................ 585
September 30, 2007........................................ 585
September 30, 2008........................................ 585
NATURAL GAS
UTILITY MARKETING TOTAL
------- ----------- -------
(IN THOUSANDS)
SEPTEMBER 30, 2003:
Assets from risk management activities, current....... $ 202 $22,057 $22,259
Assets from risk management activities, noncurrent.... -- 1,699 1,699
Liabilities from risk management activities,
current............................................. (7,941) (12,849) (20,790)
Liabilities from risk management activities,
noncurrent.......................................... -- (763) (763)
------- ------- -------
Net assets (liabilities).............................. $(7,739) $10,144 $ 2,405
======= ======= =======
SEPTEMBER 30, 2002:
Assets from risk management activities, current....... $ 4,424 $23,560 $27,984
Assets from risk management activities, noncurrent.... -- 5,241 5,241
Liabilities from risk management activities,
current............................................. -- (18,487) (18,487)
Liabilities from risk management activities,
noncurrent.......................................... -- (3,663) (3,663)
------- ------- -------
Net assets............................................ $ 4,424 $ 6,651 $11,075
======= ======= =======
NATURAL GAS
UTILITY MARKETING
------- -----------
Fair value of contracts at September 30, 2002............... $ 4,424 $ 6,651
Contracts realized/settled................................ (4,638) (1,363)
Fair value of new contracts............................... (7,525) 6,176
Other changes in value.................................... -- 7,479
Cumulative effect of accounting change.................... -- (8,799)
------- -------
Fair value of contracts at September 30, 2003............... $(7,739) $10,144
======= =======
2003 2002
-------- --------
(IN THOUSANDS)
Unsecured 11.2% Senior Notes, due 2002, payable in annual
installments of $2,000.................................... $ -- $ 2,000
Unsecured 9.76% Senior Notes, due 2004, payable in annual
installments of $3,000.................................... -- 9,000
Unsecured 9.57% Senior Notes, due 2006, payable in annual
installments of $2,000.................................... -- 8,000
Unsecured 7.95% Senior Notes, due 2006, payable in annual
installments of $1,000.................................... -- 4,000
Unsecured 8.07% Senior Notes, due 2006, payable in annual
installments of $4,000 beginning 2002..................... -- 20,000
Unsecured 10% Notes, due 2011............................... 2,303 2,303
Unsecured 7.375% Senior Notes, due 2011..................... 350,000 350,000
Unsecured 5.125% Senior Notes, due 2013..................... 250,000 --
Unsecured 8.26% Senior Notes, due 2014, payable in annual
installments of $1,818 beginning 2004..................... -- 20,000
Medium term notes
Series A, 1995-2, 6.27%, due 2010......................... 10,000 10,000
Series A, 1995-1, 6.67%, due 2025......................... 10,000 10,000
Unsecured 6.75% Debentures, due 2028........................ 150,000 150,000
First Mortgage Bonds
Series J, 9.40% due 2021.................................. 17,000 17,000
Series P, 10.43% due 2017................................. 13,750 16,250
Series Q, 9.75% due 2020.................................. 17,000 18,000
Series R, 11.32% due 2004................................. 2,160 4,300
Series T, 9.32% due 2021.................................. 18,000 18,000
Series U, 8.77% due 2022.................................. 20,000 20,000
Series V, 7.50% due 2007.................................. 6,733 10,000
Rental property, propane and other term notes due in
installments through 2013................................. 6,317 3,590
-------- --------
Total long-term debt................................... 873,263 692,443
Less current maturities..................................... (9,345) (21,980)
-------- --------
$863,918 $670,463
======== ========
2004............................................. $ 9,345
2005............................................. 4,990
2006............................................. 6,088
2007............................................. 6,374
2008............................................. 6,132
Thereafter....................................... 840,334
--------
$873,263
========
1.25 percent through July 2003 when the interest rate was increased to LIBOR
plus 2.75%. Any outstanding amounts under this facility are subordinated to
Woodward Marketing's $210.0 million uncommitted demand credit facility described
above. At September 30, 2003, $70.0 million was outstanding under this facility.
2003 2002 2001
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER OF EXERCISE NUMBER OF EXERCISE NUMBER OF EXERCISE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
--------- -------- --------- -------- --------- --------
Outstanding at beginning of
year......................... 1,557,606 $21.87 1,009,330 $21.43 658,500 $19.76
Granted...................... 411,860 21.37 607,877 22.35 439,500 23.45
Exercised.................... (92,989) 17.79 (19,102) 16.69 (17,172) 15.82
Forfeited.................... (49,167) 23.89 (40,499) 20.53 (71,498) 19.86
--------- ------ --------- ------ --------- ------
Outstanding at end of year..... 1,827,310 $21.91 1,557,606 $21.87 1,009,330 $21.43
========= ====== ========= ====== ========= ======
Exercisable at end of year..... 868,199 $21.69 532,729 $21.81 285,448 $21.37
========= ====== ========= ====== ========= ======
OPTIONS OUTSTANDING
----------------------------------
WEIGHTED OPTIONS EXERCISABLE
AVERAGE --------------------
REMAINING WEIGHTED WEIGHTED
CONTRACTUAL AVERAGE AVERAGE
NUMBER OF LIFE EXERCISE NUMBER OF EXERCISE
RANGE OF EXERCISE PRICES OPTIONS (IN YEARS) PRICE OPTIONS PRICE
------------------------ --------- ----------- -------- --------- --------
$14.68 to $17.49................. 183,898 6.4 $15.62 183,898 $15.62
$17.50 to $20.24................. 24,000 6.9 $19.74 24,000 $19.74
$20.25 to $22.99................. 1,017,912 8.7 $21.93 206,834 $22.29
$23.00 to $25.66................. 601,500 6.8 $23.88 453,467 $23.99
--------- -------
$14.68 to $25.66................. 1,827,310 7.8 $21.91 868,199 $21.69
========= =======
YEAR ENDED
SEPTEMBER 30
------------------
2003 2002 2001
---- ---- ----
Expected Life (years)....................................... 7 7 5
Interest rate............................................... 4.0% 3.9% 4.7%
Volatility.................................................. 23.3% 24.2% 25.5%
Dividend yield.............................................. 4.8% 4.8% 4.9%
YEAR ENDED SEPTEMBER 30
----------------------------
2003 2002 2001
-------- ------- -------
Shares granted during the year......................... 82,933 22,204 --
Weighted average intrinsic value....................... $ 21.34 $ 21.30 --
Compensation expense recognized, net of tax (in
thousands)........................................... $ 370 $ 487 $ 708
Unexpired shares with unmet restrictions at September
30................................................... 101,486 54,079 79,575
2003 2002
-------- --------
(IN THOUSANDS)
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year................... $226,197 $210,878
Service cost.............................................. 6,693 5,247
Interest cost............................................. 19,044 15,544
Actuarial loss............................................ 47,410 12,732
MVG acquisition........................................... 52,210 --
Plan amendments........................................... (1,771) --
Benefits paid............................................. (19,439) (18,204)
-------- --------
Benefit obligation at end of year......................... 330,344 226,197
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year............ 209,941 246,327
Actual return on plan assets.............................. 8,513 (18,182)
MVG acquisition........................................... 46,326 --
Employer contributions.................................... 77,362 --
Benefits paid............................................. (19,439) (18,204)
-------- --------
Fair value of plan assets at end of year.................. 322,703 209,941
-------- --------
RECONCILIATION:
Funded status............................................. (7,641) (16,256)
Unrecognized prior service cost........................... (7,995) (7,112)
Unrecognized net loss..................................... 132,332 71,233
-------- --------
Net amount recognized..................................... $116,696 $ 47,865
======== ========
2003 2002 2001
----- ----- ------
Discount rate............................................... 6.00% 7.25% 7.50%
Rate of compensation increase............................... 4.00% 4.00% 4.00%
Expected return on plan assets.............................. 9.00% 9.25% 10.00%
YEAR ENDED SEPTEMBER 30
------------------------------
2003 2002 2001
-------- -------- --------
(IN THOUSANDS)
Components of net periodic pension cost:
Service cost....................................... $ 6,693 $ 5,247 $ 3,557
Interest cost...................................... 19,044 15,544 16,408
Expected return on assets.......................... (23,950) (23,298) (27,093)
Amortization of transition asset................... -- (72) (290)
Amortization of prior service cost................. (883) (883) (883)
Recognized actuarial gain.......................... 1,756 -- --
-------- -------- --------
Net periodic pension cost....................... $ 2,660 $ (3,462) $ (8,301)
======== ======== ========
2003 2002
-------- --------
(IN THOUSANDS)
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year................... $ 59,152 $ 52,845
Service cost.............................................. 1,548 1,028
Interest cost............................................. 4,294 3,938
Actuarial loss............................................ 9,900 4,227
Benefits paid............................................. (3,235) (2,886)
-------- --------
Benefit obligation at end of year......................... 71,659 59,152
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year............ -- --
Employer contribution..................................... 3,235 2,886
Benefits paid............................................. (3,235) (2,886)
-------- --------
Fair value of plan assets at end of year.................. -- --
-------- --------
RECONCILIATION:
Funded status............................................. (71,659) (59,152)
Unrecognized transition obligation........................ 100 196
Unrecognized prior service cost........................... 4,750 5,772
Unrecognized net loss..................................... 24,349 15,221
-------- --------
Accrued pension cost...................................... $(42,460) $(37,963)
======== ========
2003 2002 2001
---- ---- ----
Discount rate............................................... 6.00% 7.25% 7.50%
Rate of compensation increase............................... 4.00% 4.00% 4.00%
Expected return on plan assets.............................. NA NA NA
UNREALIZED
HOLDING MARKET
COST GAIN (LOSS) VALUE
------- ----------- -------
(IN THOUSANDS)
AS OF SEPTEMBER 30, 2003:
Domestic equity mutual funds........................ $28,540 $(2,359) $26,181
Foreign equity mutual funds......................... 3,195 9 3,204
------- ------- -------
$31,735 $(2,350) $29,385
======= ======= =======
AS OF SEPTEMBER 30, 2002:
Domestic equity mutual funds........................ $28,788 $(3,113) $25,675
Foreign equity mutual funds......................... 2,087 (27) 2,060
------- ------- -------
$30,875 $(3,140) $27,735
======= ======= =======
YEAR ENDED SEPTEMBER 30
------------------------
2003 2002 2001
------ ------ ------
(IN THOUSANDS)
Components of net periodic pension cost:
Service cost............................................. $1,548 $1,028 $ 832
Interest cost............................................ 4,294 3,938 3,751
Amortization of transition asset......................... 96 96 96
Amortization of prior service cost....................... 1,022 1,022 1,022
Recognized actuarial loss................................ 772 542 325
------ ------ ------
Net periodic pension cost............................. $7,732 $6,626 $6,026
====== ====== ======
ATMOS PENSION ACCOUNT SUPPLEMENTAL
PLAN PLANS
--------------------- -----------------
2003 2002 2003 2002
--------- --------- ------- -------
(IN THOUSANDS)
Projected Benefit Obligation................. $330,344 $226,197 $71,659 $59,152
Accumulated Benefit Obligation............... 323,663 225,124 62,642 53,191
Fair Value of Plan Assets.................... 322,703 209,941 -- --
2003 2002
-------- --------
(IN THOUSANDS)
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year................... $112,295 $ 82,850
Service cost.............................................. 5,902 2,891
Interest cost............................................. 9,078 6,199
Plan participants' contributions.......................... 306 312
Actuarial loss............................................ 5,786 26,270
MVG acquisition........................................... 13,647 --
Benefits paid............................................. (9,729) (6,227)
-------- --------
Benefit obligation at end of year......................... 137,285 112,295
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year............ 16,250 13,854
Actual return on plan assets.............................. (4,056) 2,396
Employer contributions.................................... 18,618 5,915
Plan participants' contributions.......................... 306 312
MVG acquisition........................................... 4,921 --
Benefits paid............................................. (9,729) (6,227)
-------- --------
Fair value of plan assets at end of year.................. 26,310 16,250
-------- --------
RECONCILIATION:
Funded status............................................... (110,975) (96,045)
Unrecognized transition obligation.......................... 15,687 17,198
Unrecognized prior service cost............................. 1,166 1,534
Unrecognized net loss....................................... 38,543 29,466
-------- --------
Accrued postretirement cost................................. $(55,579) $(47,847)
======== ========
2003 2002 2001
---- ----- ----
Discount rate............................................... 6.00% 7.25% 7.50%
Expected return on plan assets.............................. 5.30% 5.30% 5.30%
Initial trend rate.......................................... 9.00% 10.00% 7.00%
Ultimate trend rate......................................... 5.00% 5.00% 5.00%
Number of years from initial to ultimate trend.............. 5 6 3
YEAR ENDED SEPTEMBER 30
--------------------------
2003 2002 2001
------- ------- ------
(IN THOUSANDS)
Components of net periodic postretirement cost:
Service cost........................................... $ 5,902 $ 2,891 $2,274
Interest cost.......................................... 9,078 6,199 5,434
Expected return on assets.............................. (1,012) (759) (653)
Amortization of transition obligation.................. 1,511 1,511 1,511
Amortization of prior service cost..................... 368 520 520
Recognized actuarial loss.............................. 1,778 -- --
------- ------- ------
Net periodic postretirement cost.................... $17,625 $10,362 $9,086
======= ======= ======
1-PERCENTAGE 1-PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN THOUSANDS)
Effect on total service and interest cost components...... $ 1,720 $(1,570)
Effect on postretirement benefit obligation............... $10,980 $(9,610)
SEPTEMBER 30
-----------------
2003 2002
------- -------
(IN THOUSANDS)
Assets from risk management activities...................... $22,259 $27,984
Prepaid expenses............................................ 8,187 7,338
Materials and supplies...................................... 3,917 3,769
Deferred gas costs.......................................... 308 --
Other....................................................... 4,192 5,871
------- -------
Total....................................................... $38,863 $44,962
======= =======
SEPTEMBER 30
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS)
Production plant............................................ $ 8,003 $ 9,017
Storage plant............................................... 64,714 53,527
Transmission plant.......................................... 122,014 97,708
Distribution plant.......................................... 1,851,228 1,572,549
General plant............................................... 376,777 340,419
Intangible plant............................................ 41,256 30,208
---------- ----------
2,463,992 2,103,428
Construction in progress.................................... 16,147 24,399
---------- ----------
2,480,139 2,127,827
Less: accumulated depreciation and amortization............. (964,150) (827,507)
---------- ----------
Net property, plant and equipment......................... $1,515,989 $1,300,320
========== ==========
SEPTEMBER 30
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
Pension plan assets in excess of plan obligations........... $116,696 $ --
Marketable securities....................................... 29,385 27,735
Long-term receivable on leased assets....................... 25,403 8,845
Investment in U.S. Propane.................................. 21,071 22,175
Regulatory assets........................................... 34,591 35,698
Rights of way............................................... 11,746 --
Deferred financing costs.................................... 8,867 8,944
Assets from risk management activities...................... 1,699 5,241
Prepaid weather insurance premiums.......................... -- 8,825
Other....................................................... 21,565 42,067
-------- --------
Total....................................................... $271,023 $159,530
======== ========
SEPTEMBER 30
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
Customer deposits........................................... $ 41,068 $ 31,147
Accrued employee costs...................................... 11,480 14,620
Deferred gas costs.......................................... -- 21,947
Accrued interest............................................ 20,972 18,557
Liabilities from risk management activities................. 20,790 18,487
Taxes payable............................................... 9,746 15,626
Post-retirement obligations................................. 5,300 5,300
Other....................................................... 18,567 34,043
-------- --------
Total....................................................... $127,923 $159,727
======== ========
SEPTEMBER 30
-------------------
2003 2002
-------- --------
(IN THOUSANDS)
Post-retirement obligations................................. $ 50,279 $ 42,547
Nonqualified retirement plan obligation..................... 42,460 37,963
Defined benefit plan obligations............................ -- 15,735
Customer advances for construction.......................... 13,701 12,049
Liabilities from risk management activities................. 763 3,663
Deferred revenue............................................ 12,197 3,290
Other....................................................... 18,608 23,629
-------- --------
Total....................................................... $138,008 $138,876
======== ========
2003 2002 2001
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Income before cumulative effect of accounting
change.............................................. $79,461 $59,656 $56,090
Cumulative effect of accounting change, net of income
tax benefit......................................... (7,773) -- --
------- ------- -------
Net income............................................ $71,688 $59,656 $56,090
======= ======= =======
Denominator for basic income per share -- weighted
average common shares............................... 46,319 41,171 38,156
Effect of dilutive securities:
Restricted stock.................................... 109 54 79
Stock options....................................... 68 25 12
------- ------- -------
Denominator for diluted income per share -- weighted
average common shares............................... 46,496 41,250 38,247
======= ======= =======
Income per share -- basic:
Before cumulative effect of accounting change....... $ 1.72 $ 1.45 $ 1.47
Cumulative effect of accounting change, net of
income tax benefit............................... (.17) -- --
------- ------- -------
Net income per share................................ $ 1.55 $ 1.45 $ 1.47
======= ======= =======
Income per share -- diluted:
Before cumulative effect of accounting change....... $ 1.71 $ 1.45 $ 1.47
Cumulative effect of accounting change, net of
income tax benefit............................... (.17) -- --
------- ------- -------
Net income per share................................ $ 1.54 $ 1.45 $ 1.47
======= ======= =======
2003 2002 2001
-------- ------- -------
(IN THOUSANDS)
Current
Federal.............................................. $(13,446) $17,638 $13,624
State................................................ (441) 3,575 2,189
Deferred
Federal.............................................. 54,656 12,964 14,971
State................................................ 6,690 1,420 3,013
Investment tax credits................................. (549) (417) (429)
-------- ------- -------
$ 46,910 $35,180 $33,368
======== ======= =======
2003 2002 2001
------- ------- -------
(IN THOUSANDS)
Income before cumulative effect of accounting change.... $46,910 $35,180 $33,368
Cumulative effect of accounting change.................. (5,117) -- --
------- ------- -------
Income tax expense...................................... $41,793 $35,180 $33,368
======= ======= =======
2003 2002 2001
------- ------- -------
(IN THOUSANDS)
Tax at statutory rate of 35%............................ $44,230 $33,193 $31,310
Common stock dividends deductible for tax reporting..... (993) (707) (857)
State taxes (net of federal benefit).................... 4,062 3,489 3,652
Other, net.............................................. (389) (795) (737)
------- ------- -------
Income tax expense...................................... $46,910 $35,180 $33,368
======= ======= =======
2003 2002
--------- ---------
(IN THOUSANDS)
DEFERRED TAX ASSETS:
Costs expensed for book purposes and capitalized for tax
purposes............................................... $ 2,336 $ 2,398
Accruals not currently deductible for tax purposes........ 5,254 3,968
Customer advances......................................... 6,158 4,578
Nonqualified benefit plans................................ 17,435 14,325
Postretirement benefits................................... 21,186 22,153
Unamortized investment tax credit......................... 564 902
Regulatory liabilities.................................... 1,271 1,328
Tax net operating loss and credit carryforwards........... 29,257 6,377
Other, net................................................ 7,198 9,201
--------- ---------
Total deferred tax assets.............................. 90,659 65,230
DEFERRED TAX LIABILITIES:
Difference in net book value and net tax value of
assets................................................. (257,679) (194,573)
Pension funding........................................... (42,681) 6,450
Gas cost adjustments...................................... (429) 6,464
Regulatory assets......................................... (3,154) (3,154)
Cost capitalized for book purposes and expensed for tax
purposes............................................... (8,054) (7,717)
Other, net................................................ (2,012) (7,240)
--------- ---------
Total deferred tax liabilities......................... (314,009) (199,770)
--------- ---------
Net deferred tax liabilities................................ $(223,350) $(134,540)
========= =========
SFAS No. 109 deferred credits for rate regulated entities... $ 2,080 $ 1,704
========= =========
MINIMUM
LEASE RECEIPTS
--------------
(IN THOUSANDS)
2004........................................................ $ 2,973
2005........................................................ 2,973
2006........................................................ 2,973
2007........................................................ 2,973
2008........................................................ 2,973
Thereafter.................................................. 13,513
-------
Total minimum lease receipts................................ $28,378
=======
CAPITAL OPERATING
LEASES LEASES
------- ---------
(IN THOUSANDS)
2004........................................................ $ 876 $10,331
2005........................................................ 843 9,684
2006........................................................ 433 9,137
2007........................................................ 433 7,271
2008........................................................ 362 5,685
Thereafter.................................................. 2,178 16,817
------- -------
Total minimum lease payments................................ 5,125 $58,925
=======
Less amount representing interest........................... (2,113)
-------
Present value of net minimum lease payments................. $ 3,012
=======
AT SEPTEMBER 30, 2003
------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY
SEGMENT(1) SEGMENT SEGMENT CONSOLIDATED
----------- ----------- ----------- ------------
(IN THOUSANDS)
Investment grade counterparties......... $202 $10,866 $-- $11,068
Non-investment grade counterparties..... -- 12,890 -- 12,890
---- ------- --- -------
$202 $23,756 $-- $23,958
==== ======= === =======
2003 2002 2001
------- ------- -------
(IN THOUSANDS)
Cash paid for interest.................................. $62,088 $59,639 $41,042
Cash paid for income taxes.............................. $ 408 $16,588 $16,808
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
========== ========== ======= ========= ==========
Capital expenditures.............. $ 154,777 $ 1,884 $ 2,778 $ -- $ 159,439
========== ========== ======= ========= ==========
FOR THE YEAR ENDED SEPTEMBER 30, 2002
------------------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
-------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
Operating revenues from external
parties.......................... $936,054 $ 700,519 $14,391 $ -- $1,650,964
Intersegment revenues.............. 1,472 331,355 10,314 (343,141) --
-------- ---------- ------- --------- ----------
937,526 1,031,874 24,705 (343,141) 1,650,964
Purchased gas cost................. 559,891 994,318 8,022 (342,407) 1,219,824
-------- ---------- ------- --------- ----------
Gross profit..................... 377,635 37,556 16,683 (734) 431,140
Depreciation and amortization...... 77,704 2,069 1,696 -- 81,469
Other operating expenses........... 174,425 14,877 5,772 (734) 194,340
-------- ---------- ------- --------- ----------
Operating income................... 125,506 20,610 9,215 -- 155,331
Miscellaneous income (expense)..... 1,427 1,331 554 (4,633) (1,321)
Interest charges................... 58,796 2,866 2,145 (4,633) 59,174
-------- ---------- ------- --------- ----------
Income before income taxes......... 68,137 19,075 7,624 -- 94,836
Income tax expense................. 25,143 6,461 3,576 -- 35,180
-------- ---------- ------- --------- ----------
Net income.................... $ 42,994 $ 12,614 $ 4,048 $ -- $ 59,656
======== ========== ======= ========= ==========
Capital expenditures............... $129,632 $ 779 $ 1,841 $ -- $ 132,252
======== ========== ======= ========= ==========
FOR THE YEAR ENDED SEPTEMBER 30, 2001
--------------------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
Operating revenues from external
parties......................... $1,378,159 $291,152 $56,170 $ -- $1,725,481
Intersegment revenues............. 1,989 155,944 3,266 (161,199) --
---------- -------- ------- --------- ----------
1,380,148 447,096 59,436 (161,199) 1,725,481
Purchased gas cost................ 1,017,363 445,504 48,605 (161,199) 1,350,273
---------- -------- ------- --------- ----------
Gross profit.................... 362,785 1,592 10,831 -- 375,208
Depreciation and amortization..... 65,614 1,062 988 -- 67,664
Other operating expenses.......... 170,663 3,733 4,339 (1,472) 177,263
---------- -------- ------- --------- ----------
Operating income (loss)........... 126,508 (3,203) 5,504 1,472 130,281
Equity in earnings of Woodward
Marketing L.L.C................. -- 8,062 -- -- 8,062
Miscellaneous income (expense).... (864) 1,819 1,539 (4,368) (1,874)
Interest charges.................. 46,351 2,611 945 (2,896) 47,011
---------- -------- ------- --------- ----------
Income before income taxes........ 79,293 4,067 6,098 -- 89,458
Income tax expense................ 29,412 1,516 2,440 -- 33,368
---------- -------- ------- --------- ----------
Net income................... $ 49,881 $ 2,551 $ 3,658 $ -- $ 56,090
========== ======== ======= ========= ==========
Capital expenditures.............. $ 112,683 $ 32 $ 394 $ -- $ 113,109
========== ======== ======= ========= ==========
2003 2002 2001
---------- ---------- ----------
(IN THOUSANDS)
Utility revenues:
Gas sales revenues:
Residential................................. $ 873,375 $ 535,981 $ 788,902
Commercial.................................. 367,961 221,728 342,945
Public authority and other.................. 65,921 31,731 58,539
Industrial.................................. 192,676 98,765 148,180
---------- ---------- ----------
Total gas sales revenues.................. 1,499,933 888,205 1,338,566
Transportation revenues........................ 29,583 36,591 28,668
Other gas revenues............................. 23,341 11,258 10,925
---------- ---------- ----------
Total utility revenues...................... 1,552,857 936,054 1,378,159
Natural gas marketing revenues................... 1,234,447 700,519 291,152
Other non-utility revenues....................... 12,612 14,391 56,170
---------- ---------- ----------
Total operating revenues.................... $2,799,916 $1,650,964 $1,725,481
========== ========== ==========
AT SEPTEMBER 30, 2003
--------------------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
ASSETS
Property, plant and equipment,
net......................... $1,446,976 $ 9,288 $ 59,725 $ -- $1,515,989
Investment in subsidiaries.... 133,586 (2,662) -- (130,924) --
Current assets
Cash and cash equivalents... -- 14,880 803 -- 15,683
Assets from risk management
activities............... 202 22,941 -- (884) 22,259
Other current assets........ 230,609 197,239 85,119 (92,912) 420,055
Intercompany receivables.... 114,550 -- -- (114,550) --
---------- -------- -------- --------- ----------
Total current assets..... 345,361 235,060 85,922 (208,346) 457,997
Intangible assets............. -- 5,030 -- -- 5,030
Goodwill...................... 233,741 22,600 12,128 -- 268,469
Noncurrent assets from risk
management activities....... -- 1,896 -- (197) 1,699
Investment in US Propane
LLC......................... -- -- 21,071 -- 21,071
Deferred charges and other
assets...................... 220,258 2,214 25,781 -- 248,253
---------- -------- -------- --------- ----------
$2,379,922 $273,426 $204,627 $(339,467) $2,518,508
========== ======== ======== ========= ==========
CAPITALIZATION AND LIABILITIES
Shareholders' equity.......... $ 857,517 $ 74,759 $ 58,827 $(133,586) $ 857,517
Long-term debt................ 858,720 -- 5,198 -- 863,918
---------- -------- -------- --------- ----------
Total capitalization..... 1,716,237 74,759 64,025 (133,586) 1,721,435
Current liabilities
Current maturities of
long-term debt........... 8,227 -- 1,118 -- 9,345
Short-term debt............. 118,595 -- -- -- 118,595
Liabilities from risk
management activities.... 7,941 13,400 -- (551) 20,790
Other current liabilities... 184,365 183,082 10,008 (90,470) 286,985
Intercompany payables....... -- 5,549 109,001 (114,550) --
---------- -------- -------- --------- ----------
Total current
liabilities............ 319,128 202,031 120,127 (205,571) 435,715
Deferred income taxes......... 221,912 (9,498) 11,081 (145) 223,350
Noncurrent liabilities from
risk management
activities.................. -- 928 -- (165) 763
Deferred credits and other
liabilities................. 122,645 5,206 9,394 -- 137,245
---------- -------- -------- --------- ----------
$2,379,922 $273,426 $204,627 $(339,467) $2,518,508
========== ======== ======== ========= ==========
AT SEPTEMBER 30, 2002
--------------------------------------------------------------------
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
ASSETS
Property, plant and
equipment, net.......... $1,223,901 $ 9,893 $ 66,526 $ -- $1,300,320
Investment in
subsidiaries............ 122,988 (5,752) -- (117,236) --
Current assets
Cash and cash
equivalents.......... -- 47,887 104 -- 47,991
Assets from risk
management
activities........... 4,424 28,909 -- (5,349) 27,984
Other current assets.... 126,066 141,526 4,275 (16,687) 255,180
Intercompany
receivables.......... 76,174 -- -- (76,174) --
---------- -------- -------- --------- ----------
Total current
assets............. 206,664 218,322 4,379 (98,210) 331,155
Intangible assets......... -- 5,365 -- -- 5,365
Goodwill.................. 150,287 21,288 13,440 -- 185,015
Noncurrent assets from
risk management
activities.............. -- 5,241 -- -- 5,241
Investment in US Propane
LLC..................... -- -- 22,175 -- 22,175
Deferred charges and other
assets.................. 87,157 37,294 7,663 -- 132,114
---------- -------- -------- --------- ----------
$1,790,997 $291,651 $114,183 $(215,446) $1,981,385
========== ======== ======== ========= ==========
CAPITALIZATION AND
LIABILITIES
Shareholders' equity...... $ 573,235 $ 75,675 $ 47,313 $(122,988) $ 573,235
Long-term debt............ 667,946 -- 2,517 -- 670,463
---------- -------- -------- --------- ----------
Total
capitalization..... 1,241,181 75,675 49,830 (122,988) 1,243,698
Current liabilities
Current maturities of
long-term debt....... 20,907 -- 1,073 -- 21,980
Short-term debt......... 145,791 -- -- -- 145,791
Liabilities from risk
management
activities........... -- 18,487 -- -- 18,487
Other current
liabilities.......... 134,138 151,046 9,113 (16,284) 278,013
Intercompany payables... -- 33,027 43,147 (76,174) --
---------- -------- -------- --------- ----------
Total current
liabilities........ 300,836 202,560 53,333 (92,458) 464,271
Deferred income taxes..... 130,575 (3,227) 7,192 -- 134,540
Noncurrent liabilities
from risk management
activities.............. -- 3,663 -- -- 3,663
Deferred credits and other
liabilities............. 118,405 12,980 3,828 -- 135,213
---------- -------- -------- --------- ----------
$1,790,997 $291,651 $114,183 $(215,446) $1,981,385
========== ======== ======== ========= ==========
2003 2002 2001
-------- -------- --------
Gas purchases(1):
Dollars (in thousands)............................. $333,390 $190,594 $525,568
Volumes (Mcf)...................................... 62,729 67,657 96,252
Average sales price per Mcf........................ $ 5.31 $ 2.82 $ 5.46
Storage contract fees (in thousands)................. $ 4,236 $ 4,305 $ 3,366
QUARTER ENDED
--------------------------------------------------
DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30
----------- ---------- -------- ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
FISCAL YEAR 2003:
Operating revenues
Utility segment.................. $399,968 $ 696,561 $245,998 $211,555
Natural gas marketing segment.... 343,498 620,402 374,832 329,761
Other non-utility segment........ 2,900 9,657 3,685 5,388
Intersegment eliminations........ (65,934) (132,478) (136,045) (109,832)
-------- ---------- -------- --------
680,432 1,194,142 488,470 436,872
Gross profit........................ 137,166 202,968 95,064 99,778
Operating income.................... 52,624 107,878 14,056 13,282
Income (loss) before cumulative
effect of accounting change...... 25,793 56,305 (201) (2,436)
Cumulative effect of accounting
change, net of income tax
benefit.......................... -- (7,773) -- --
Net income (loss)................... 25,793 48,532 (201) (2,436)
Income (loss) before cumulative
effect of accounting change per
basic and diluted share.......... $ .60 $ 1.24 $ (.00) $ (.05)
Cumulative effect of accounting
change, net of income tax
benefit, per basic and diluted
share............................ $ -- $ (.17) $ -- $ --
-------- ---------- -------- --------
Net income (loss) per basic and
diluted share.................... $ .60 $ 1.07 $ (.00) $ (.05)
======== ========== ======== ========
FISCAL YEAR 2002:
Operating revenues
Utility segment.................. $265,156 $ 376,811 $159,493 $136,066
Natural gas marketing segment.... 254,042 256,172 282,396 239,264
Other non-utility segment........ 7,466 9,494 3,888 3,857
Intersegment eliminations........ (86,510) (112,218) (57,672) (86,741)
-------- ---------- -------- --------
440,154 530,259 388,105 292,446
Gross profit........................ 116,528 159,487 86,092 69,033
Operating income.................... 43,446 86,333 19,178 6,374
Net income (loss)................... 20,633 41,378 3,254 (5,609)
Net income (loss) per basic share... $ .51 $ 1.01 $ .08 $ (.14)
Net income (loss) per diluted
share............................ $ .50 $ 1.01 $ .08 $ (.14)
STOCKHOLDER MATTERS
By: /s/ JOHN P. REDDY
------------------------------------
John P. Reddy
Senior Vice President
and Chief Financial Officer
/s/ ROBERT W. BEST Chairman, President and Chief November 21, 2003
-------------------------------------- Executive Officer
Robert W. Best
/s/ JOHN P. REDDY Senior Vice President and Chief November 21, 2003
-------------------------------------- Financial Officer
John P. Reddy
/s/ F.E. MEISENHEIMER Vice President and Controller November 21, 2003
-------------------------------------- (Principal Accounting Officer)
F.E. Meisenheimer
/s/ TRAVIS W. BAIN, II Director November 21, 2003
--------------------------------------
Travis W. Bain, II
/s/ DAN BUSBEE Director November 21, 2003
--------------------------------------
Dan Busbee
/s/ RICHARD W. CARDIN Director November 21, 2003
--------------------------------------
Richard W. Cardin
/s/ THOMAS J. GARLAND Director November 21, 2003
--------------------------------------
Thomas J. Garland
/s/ RICHARD K. GORDON Director November 21, 2003
--------------------------------------
Richard K. Gordon
/s/ GENE C. KOONCE Director November 21, 2003
--------------------------------------
Gene C. Koonce
/s/ THOMAS C. MEREDITH Director November 21, 2003
--------------------------------------
Thomas C. Meredith
/s/ PHILLIP E. NICHOL Director November 21, 2003
--------------------------------------
Phillip E. Nichol
/s/ CARL S. QUINN Director November 21, 2003
--------------------------------------
Carl S. Quinn
/s/ CHARLES K. VAUGHAN Director November 21, 2003
--------------------------------------
Charles K. Vaughan
/s/ RICHARD WARE II Director November 21, 2003
--------------------------------------
Richard Ware II
ADDITIONS
-----------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COST & OTHER AT END OF
OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
---------- ---------- ---------- ---------- ---------
2003
Allowance for doubtful accounts...... $10,509 $13,249 $ -- $10,707(2) $13,051
2002
Allowance for doubtful accounts...... $16,151 $ -- $1,500(1) $ 7,142(2) $10,509
2001
Allowance for doubtful accounts...... $10,589 $26,226 -- $20,664(2) $16,151
(1) This amount was charged to regulatory assets within deferred charges and other assets as recovery was specifically permitted by the relevant regulators.
(2) Uncollectible accounts written off.
ITEM 14.(A)(3)
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
Plan of Reorganization
2.1 Purchase and Sale Agreement (Louisiana Gas Exhibit 2.1 to Registration Statement on
Operations), by and among Citizens Utilities Form S-3/A filed November 6, 2000 (File No.
Company (now known as Citizens Communications 333-73705)
Company), LGS Natural Gas Company and Atmos
Energy Corporation, dated as of April 13,
2000
2.2 Agreement and Plan of Merger and Exhibit 2.2 of Form 10-K for fiscal year
Reorganization dated as of September 21, ended September 30, 2001 (File No. 1-10042)
2001, by and among Atmos Energy Corporation,
Mississippi Valley Gas Company and the
Shareholders Named on the Signature Pages
hereto Articles of Incorporation and Bylaws
3.1(a) Restated Articles of Incorporation of the Exhibit 3.1 of Form 10-K for fiscal year
Company, as Amended (as of July 31, 1997) ended September 30, 1997 (File No. 1-10042)
3.1(b) Articles of Amendment to the Restated Exhibit 3a of Form 10-Q for quarter ended
Articles of Incorporation of Atmos Energy March 31, 1999 (File No. 1- 10042)
Corporation as Amended (Texas)
3.1(c) Articles of Amendment to the Restated Exhibit 3b of Form 10-Q for quarter ended
Articles of Incorporation of Atmos Energy March 31, 1999 (File No. 1- 10042)
Corporation as Amended (Virginia)
3.2(a) Bylaws of the Company (Amended and Restated Exhibit 3.2 of Form 10-K for fiscal year
as of November 12, 1997) ended September 30, 1997 (File No. 1-10042)
3.2(b) Amendment No. 1 to Bylaws of Atmos Energy Exhibit 3.1 of Form 10-Q for quarter ended
Corporation (Amended and Restated as of March 31, 2001 (File No. 1- 10042)
November 12, 1997)
3.2(c) Amendment No. 2 to Bylaws of Atmos Energy
Corporation (Amended and Restated as of
November 12, 1997)
Instruments Defining Rights of Security
Holders
4.1 Specimen Common Stock Certificate (Atmos En- Exhibit (4)(b) of Form 10-K for fiscal year
ergy Corporation) ended September 30, 1988 (File No. 1-10042)
4.2 Rights Agreement, dated as of November 12, Exhibit 4.1 of Form 8-K dated November 12,
1997, between the Company and BankBoston, 1997 (File No. 1-10042)
N.A., as Rights Agent
4.3 First Amendment to Rights Agreement dated as Exhibit 2 of Form 8-A, Amendment No. 1,
of August 11, 1999, between the Company and dated August 12, 1999 (File No. 1-10042)
BankBoston, N.A., as Rights Agent
4.4 Second Amendment to Rights Agreement dated as Exhibit 4 of Form 10-Q for quarter ended
of February 13, 2002, between the Company and December 31, 2001 (File No. 1-10042)
EquiServe Trust Company, N.A., as Rights
Agent
4.5 Registration Rights Agreement, dated as of Exhibit 4.1 of Form 10-Q for quarter ended
June 30, 2003, between Atmos Energy June 30, 2003 (File No. 1-10042)
Corporation and Gary A. Morris, as Asset
Manager
4.6 Registration Rights Agreement, dated as of Exhibit 99.2 of Form 8-K/A, dated December
December 3, 2002, by and among Atmos Energy 3, 2002 (File No. 1-10042)
Corporation and the Shareholders of
Mississippi Valley Gas Company
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
4.7 Standstill Agreement, dated as of December 3, Exhibit 99.3 of Form 8-K/A, dated December
2002, by and among Atmos Energy Corporation 3, 2002 (File No. 1-10042)
and the Shareholders of Mississippi Valley
Gas Company
4.8 Form of Indenture between Atmos Energy Exhibit 4.1 to Registration Statement on
Corporation and U.S. Bank Trust National Form S-3 filed April 20, 1998 (File No.
Association, Trustee 333-50477)
4.9 Indenture between Atmos Energy Corporation, Exhibit 99.3 of Form 8-K dated May 15, 2001
as Issuer, and Suntrust Bank, Trustee dated (File No. 1-10042)
as of May 22, 2001
4.10(a) Indenture of Mortgage, dated as of July 15, Exhibit to Registration Statement of United
1959, from United Cities Gas Company to First Cities Gas Company on Form S-3 (File No.
Trust of Illinois, National Association, and 33-56983)
M.J. Kruger, as Trustees, as amended and
supplemented through December 1, 1992 (the
Indenture of Mortgage through the 20th
Supplemental Indenture)
4.10(b) Twenty-First Supplemental Indenture dated as Exhibit 10.7(a) of Form 10-K for fiscal year
of February 5, 1997 by and among United ended September 30, 1997 (File No. 1-10042)
Cities Gas Company and Bank of America
Illinois and First Trust National Association
and Russell C. Bergman supplementing
Indenture of Mortgage dated as of July 15,
1959
4.10(c) Twenty-Second Supplemental Indenture dated as Exhibit 10.7(b) of Form 10-K for fiscal year
of July 29, 1997 by and among the Company and ended September 30, 1997 (File No. 1-10042)
First Trust National Association and Russell
C. Bergman supplementing Indenture of
Mortgage dated as of July 15, 1959
4.11(a) Form of Indenture between United Cities Gas Exhibit to Registration Statement of United
Company and First Trust of Illinois, National Cities Gas Company on Form S-3 (File No.
Association, as Trustee dated as of November 33-56983)
15, 1995
4.11(b) First Supplemental Indenture between the Exhibit 10.8(a) of Form 10-K for fiscal year
Company and First Trust of Illinois, National ended September 30, 1997 (File No. 1-10042)
Association, as Trustee dated as of July 29,
1997
4.12(a) Seventh Supplemental Indenture, dated as of Exhibit 10.1 of Form 10-Q for quarter ended
October 1, 1983 between Greeley Gas Company June 30, 1994 (File No. 1-10042)
("The Greeley Gas Division") and the Central
Bank of Denver, N.A. ("Central Bank")
4.12(b) Ninth Supplemental Indenture, dated as of Exhibit 10.2 of Form 10-Q for quarter ended
April 1, 1991, between The Greeley Gas June 30, 1994 (File No. 1-10042)
Division and Central Bank
4.12(c) Tenth Supplemental Indenture, dated as of Exhibit 10.4 of Form 10-Q for quarter ended
December 1, 1993, between the Company and June 30, 1994 (File No. 1-10042)
Colorado National Bank, formerly Central Bank
9 Not Applicable
Material Contracts
10.1 Bond Purchase Agreement, dated as of April 1, Exhibit 10.3 of Form 10-Q for quarter ended
1991, between the Greeley Division and June 30, 1994 (File No. 1-10042)
Central Bank
10.2(a) Purchase Agreement for 6 3/4% Debentures due Exhibit 99.1 of Form 8-K dated July 22, 1998
2028 by and among Merrill Lynch Co., (File No. 1-10042)
NationsBanc Montgomery Securities L.L.C.,
Edward D. Jones & Co., L.P. and Atmos Energy
Corporation dated July 22, 1998
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.2(b) Purchase Agreement for 7 3/8% Senior Notes Exhibit 99.1 of Form 8-K dated May 15, 2001
due 2011 by and among Banc of America (File No. 1-10042)
Securities L.L.C., Banc One Capital Markets,
Inc., First Union Securities, Inc, Fleet
Securities, Inc, SG Cowen Securities
Corporation and Atmos Energy Corporation
dated May 15, 2001
10.2(c) Purchase Agreement for 5 1/8% Senior Notes Exhibit 1.1 of Form 8-K dated January 13,
due 2013 by and among Banc One Capital 2003 (File No. 1-10042)
Markets, Inc., SG Cowen Securities
Corporation, SunTrust Capital Markets, Inc.,
Wachovia Securities, Inc., Banc of America
Securities LLC, KBC Financial Products USA
Inc., U.S. Bancorp Piper Jaffray Inc.,
Hibernia Southcoast Capital, Inc. and Atmos
Energy Corporation dated January 13, 2003
10.2(d) Purchase Agreement for 6,741,500 Shares of Exhibit 99.1 of Form 8-K dated December 14,
Common Stock (No Par Value) by and among 2000 (File No. 1-10042)
Merrill Lynch & Co., Merrill Lynch, Pierce,
Fenner & Smith Incorporated, UBS Warburg
L.L.C., A.G. Edwards & Sons, Inc, Edward D.
Jones & Co., L.P. and Atmos Energy
Corporation dated December 14, 2000
10.2(e) Purchase Agreement for 4,100,000 Shares of Exhibit 1.1 of Form 8-K dated June 18, 2003
Common Stock (No Par Value) by and among (File No. 1-10042)
Merrill Lynch & Co., Merrill Lynch, Pierce
Fenner & Smith Incorporated, UBS Securities
LLC, A.G. Edwards & Sons, Inc., Edward D.
Jones & Co., L.P. and Atmos Energy
Corporation dated June 18, 2003
10.3(a) 364-Day Revolving Credit Agreement, dated as Exhibit 10.1 of Form 10-Q for quarter ended
of July 29, 2003, among Atmos Energy June 30, 2003 (File No. 1-10042)
Corporation, Bank One, NA, Suntrust Bank and
Bank of America, N.A. and the lenders
identified therein
10.3(b) Uncommitted Amended and Restated Credit Exhibit 10.1 of Form 10-Q for quarter ended
Agreement, dated to be effective July 1, June 30, 2002 (File No. 1-10042)
2002, among Woodward Marketing, L.L.C.,
Fortis Capital Corp., BNP Paribas and the
other financial institutions which may become
parties hereto
10.3(c) First Amendment, entered into effective as of Exhibit 10.1 of Form 10-Q for quarter ended
December 23, 2002, to the Uncommitted Amended March 31, 2003 (File No. 1-10042)
and Restated Credit Agreement, dated as of
July 1, 2002, among Woodward Marketing,
L.L.C., Fortis Capital Corp., BNP Paribas and
the other financial institutions which may
become parties hereto
10.3(d) Second Amendment, entered into effective as Exhibit 10.2 of Form 10-Q for quarter ended
of February 7, 2003, to the Uncommitted March 31, 2003 (File No. 1-10042)
Amended and Restated Credit Agreement, dated
as of July 1, 2002, among Woodward Marketing,
L.L.C., Fortis Capital Corp., BNP Paribas and
the other financial institutions which may
become parties hereto
10.3(e) Third Amendment, entered into effective as of Exhibit 10.3 of Form 10-Q for quarter ended
February 28, 2003, to the Uncommitted Amended March 31, 2003 (File No. 1-10042)
and Restated Credit Agreement, dated as of
July 1, 2002, among Woodward Marketing,
L.L.C., Fortis Capital Corp., BNP Paribas and
the other financial institutions which may
become parties hereto
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.3(f) Fourth Amendment, entered into effective as Exhibit 10.4 of Form 10-Q for quarter ended
of March 31, 2003, to the Uncommitted Amended March 31, 2003 (File No. 1-10042)
and Restated Credit Agreement, dated as of
July 1, 2002, among Woodward Marketing,
L.L.C., Fortis Capital Corp., BNP Paribas and
the other financial institutions which may
become parties hereto
10.3(g) Fifth Amendment and Waiver, entered into Exhibit 10.5 of Form 10-Q for quarter ended
effective as of April 28, 2003, to the March 31, 2003 (File No. 1-10042)
Uncommitted Amended and Restated Credit
Agreement, dated as of July 1, 2002, among
Woodward Marketing, L.L.C., Fortis Capital
Corp., BNP Paribas and the other financial
institutions which may become parties hereto
10.3(h) Sixth Amendment to Credit Agreement, Global
Amendment to Loan Documents and Waiver, en-
tered into effective as of October 1, 2003,
to the Uncommitted Amended and Restated
Credit Agreement, dated as of July 1, 2002,
among Woodward Marketing, L.L.C., Fortis
Capital Corp., BNP Paribas and the other
financial institutions which may become
parties hereto
10.3(i) Bridge Credit Agreement, dated as of October Exhibit 10.8(c) of Form 10-K for fiscal year
7, 2002, among Atmos Energy Corporation, Bank ended September 30, 2002 (File No. 1-10042)
One, NA, Wachovia Bank, National Association,
Suntrust Bank and Societe Generale, New York
Branch
Gas Supply Contracts
10.4(a) Firm Gas Service Transportation Agreement No.
123535 dated May 1, 2003 between Atmos Energy
Corporation (Colorado-Kansas Division) and
Public Service Company of Colorado
10.4(b) Transportation Storage Service Agreement No. Exhibit 10.6(b) of Form 10-K for fiscal year
TA-0544 between Greeley Gas Company and ended September 30, 1994 (File No. 1-10042)
Southern Star Central Gas Pipeline, Inc.
dated October 1, 1993, as renewed to extend
to October 1, 2008
10.4(c) Firm Transportation Service Agreement No.
33182000D, Rate Schedule TF-1, dated April 1,
2003 between Atmos Energy Corporation
(Colorado-Kansas Division) and Colorado
Interstate Gas Company
10.4(d) No-Notice Storage and Transportation Delivery
Service Agreement No. 31044000A, Rate Sched-
ule NNT-1, dated October 1, 2002 between
Atmos Energy Corporation (Colorado-Kansas
Division) and Colorado Interstate Gas Company
10.4(e) Transportation-Storage Contract No. TA-0614 Exhibit 10.6 of Form 10-Q for quarter ended
(Request 0180) between Greeley Gas Company March 31, 1998 (File No. 1-10042)
(transferred from United Cities Gas Company
effective January 1, 2000) and Southern Star
Central Gas Pipeline, Inc. dated October 1,
1993, as amended to extend to October 1, 2005
10.4(f) Transportation-Storage Contract No. TA-0611 Exhibit 10.7 of Form 10-Q for quarter ended
(Request 0002) between Greeley Gas Company March 31, 1998 (File No. 1-10042)
(transferred from United Cities Gas Company
effective January 1, 2000) and Southern Star
Central Gas Pipeline, Inc. dated October 1,
1993, as renewed to extend to October 1, 2008
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.5(a) Agreement for Firm Intrastate Transportation Exhibit 10.1 of Form 10-Q for quarter ended
of Natural Gas in the State of Louisiana March 31, 1998 (File No. 1-10042)
between Trans La (now known as Atmos Energy
Louisiana) and Louisiana Intrastate Gas
Company L.L.C. (LIG) dated December 22, 1997
and effective July 1, 1997, as amended to
extend to July 1, 2005 and for successive 1
year terms
10.5(b) Agreement for Firm 311(a)(2) Transportation Exhibit 10.2 of Form 10-Q for quarter ended
of Natural Gas in the State of Louisiana March 31, 1998 (File No. 1-10042)
between Trans La (now known as Atmos Energy
Louisiana) and Louisiana Intrastate Gas
Company L.L.C. (LIG) dated December 22, 1997
and effective July 1, 1997, as amended to
extend to July 1, 2005 and for successive 1
year terms
10.5(c) No-Notice Service Agreement No. 29865,
(formerly Contract No. 29267), Rate Schedule
NNS, dated April 1, 2002 between Atmos Energy
Corporation (Louisiana Division) and Gulf
South Pipeline Company, L.P., as amended to
extend to March 31, 2008
10.6(a) Gas Transportation Agreement between Texas Exhibit 10.3 of Form 10-Q for quarter ended
Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042)
1, 1993 (Contract No. T3355, zone 3), as
amended to extend to November 1, 2004
10.6(b) Gas Transportation Agreement between Texas Exhibit 10.4 of Form 10-Q for quarter ended
Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042)
1, 1993 (Contract No. T3819, zone 4), as
amended to extend to November 1, 2004
10.6(c) Gas Transportation Agreement between Texas Exhibit 10.5 of Form 10-Q for quarter ended
Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042)
1, 1993 (Contract No. N0210, Zone 2, Contract
No. N0340, Zone 3, Contract No. N0435, Zone
4), as amended to extend to November 1, 2004
10.7(a) Gas Transportation Agreement, Contract No. Exhibit 10.17(a) of Form 10-K for fiscal
2550, dated September 1, 1993, between year ended September 30, 1993 (File No.
Tennessee Gas Pipeline Company, a division of 1-10042)
Tenneco, Inc. ("Tennessee Gas"), and Western
Kentucky, Campbellsville Service Area, as
amended to extend to November 1, 2007
10.7(b) Gas Transportation Agreement, Contract No. Exhibit 10.17(b) of Form 10-K for fiscal
2546, dated September 1, 1993, between year ended September 30, 1993 (File No.
Tennessee Gas and Western Kentucky, Danville 1-10042)
Service Area, as amended to extend to
November 1, 2007
10.7(c) Gas Transportation Agreement, Contract No. Exhibit 10.17(c) of Form 10-K for fiscal
2385, dated September 1, 1993, between year ended September 30, 1993 (File No.
Tennessee Gas and Western Kentucky, 1-10042)
Greensburg et al Service Area, as amended to
extend to November 1, 2007
10.7(d) Gas Transportation Agreement, Contract No. Exhibit 10.17(d) of Form 10-K for fiscal
2551, dated September 1, 1993, between year ended September 30, 1993 (File No.
Tennessee Gas and Western Kentucky, 1-10042)
Harrodsburg Service Area, as amended to
extend to November 1, 2007
10.7(e) Gas Transportation Agreement, Contract No. Exhibit 10.17(e) of Form 10-K for fiscal
2548, dated September 1, 1993, between year ended September 30, 1993 (File No.
Tennessee Gas and Western Kentucky, Lebanon 1-10042)
Service Area, as amended to extend to
November 1, 2007
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.8 Transportation Service Agreement between Exhibit 10.13 of Form 10-K for fiscal year
Energas Company and ONEOK WesTex ended September 30, 2002 (File No. 1-10042)
Transmission, L.P. dated January 1, 2002, as
amended by Service Orders dated October 1,
2003 to extend to March 31, 2009
10.9 Amarillo Supply Agreement dated January 2, Exhibit 10.7(a) of Form 10-K for fiscal year
1993 between Energas and Pioneer Natural ended September 30, 1994 (File No. 1-10042)
Resources, USA, Inc. (formerly Mesa Operating
Company)
10.10(a) Gas Transportation Agreement No. 30774, Rate Exhibit 10.1 of Form 10-Q for quarter ended
Schedules FT-A and FT-GS, between United December 31, 1999 (File No. 1-10042)
Cities Gas Company and East Tennessee Natural
Gas Company dated October 1, 1999, as amended
to extend to October 31, 2004
10.10(b) Gas Transportation Agreement No. 27311 Exhibit 10.20(c) of Form 10-K for fiscal
between United Cities Gas Company and year ended September 30, 2000 (File No.
Tennessee Gas Pipeline Company dated November 1-10042)
1, 2000
10.10(c) Service Agreement No. 867760, under Rate Exhibit 10.8 of Form 10-Q for quarter ended
Schedule FT, between United Cities Gas March 31, 1998 (File No. 1-10042)
Company and Southern Natural Gas Company
dated November 1, 1993, as amended to extend
to October 31, 2005
10.10(d) Service Agreement No. 867761 under Rate Exhibit 10.9 of Form 10-Q for quarter ended
Schedule FT-NN between United Cities Gas March 31, 1998 (File No. 1-10042)
Company and Southern Natural Gas Company
dated November 1, 1993, as amended to extend
to October 31, 2005
10.10(e) FTS-1 Service Agreement No. 59572 between Exhibit 10.20(f) of Form 10-K for fiscal
United Cities Gas Company and Columbia Gulf year ended September 30, 2000 (File No.
Transmission Company dated November 1, 1998 1-10042)
10.10(f) Gas Transportation Agreement No. 34538 (Rocky Exhibit 10.20(g) of Form 10-K for fiscal
Top Expansion) between United Cities Gas Com- year ended September 30, 2000 (File No.
pany and East Tennessee Natural Gas Company 1-10042)
dated November 1, 2000
10.11 Firm Transportation Service Agreement under
Rate Schedule FTS dated November 1, 2002
between Atmos Energy Corporation (Mid-States
Division) and Ozark Gas Transmission, L.L.C.
as renewed to extend to October 31, 2004
10.12 Service Agreement #400227 for Rate Schedule Exhibit 10.18 of Form 10-K for fiscal year
SS-1 between United Cities Gas Company and ended September 30, 2002 (File No. 1-10042)
Texas Eastern Transmission Corporation dated
May 31, 2000
10.13(a) No Notice Service Agreement No. 16086 dated
November 1, 1993 between Mississippi Valley
Gas Company and Gulf South Pipeline Company
LP., (formerly Koch Gateway Pipeline Co.), as
amended to extend to March 31, 2005
10.13(b) Service Agreement No. FSNG46 under Rate
Schedule FT and/or FT-NN between Mississippi
Valley Gas Company and Southern Natural Gas
Company dated November 1, 2000
10.13(c) Firm Contract Storage Service Agreement No.
SSNG23 under Rate Schedule CSS between
Mississippi Valley Gas Company and Southern
Natural Gas Company dated November 1, 1993,
as amended to extend to October 31, 2005
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.13(d) Gas Transportation Agreement No. T018170 be-
tween Texas Gas and Mississippi Valley Gas
Company dated October 29, 2001, as amended to
extend to October 31, 2004
10.13(e) Gas Transportation Agreement No. T018171 be-
tween Texas Gas and Mississippi Valley Gas
Company dated October 29, 2001, as amended to
extend to October 31, 2004
10.13(f) Gas Transportation Agreement No. T-15793
between Texas Gas and Mississippi Valley Gas
Company dated November 5, 1999
10.13(g) Firm No-Notice Transportation Agreement No.
N-0120 between Texas Gas and Mississippi
Valley Gas Company dated November 1, 1997, as
amended to extend to October 31, 2004
10.13(h) Firm Standby Gas Storage Contract Part A and
B between Hattiesburg Gas Storage Company,
(formerly Hattiesburg Industrial Gas Sales
Company), and Mississippi Valley Gas Company
dated February 21, 1990
10.13(i) Firm Standby Gas Storage Contract Phase 1A
between Hattiesburg Gas Storage Company and
Mississippi Valley Gas Company dated August
24, 1990
10.13(j) Gas Transportation Agreement Contract No.
1443 between Tennessee Gas Pipeline and
Mississippi Valley Gas Company dated
September 1, 1993, as automatically renewed
to extend to August 31, 2007
10.13(k) Gas Transportation Agreement Contract No.
1478 (winter only) between Tennessee Gas
Pipeline and Mississippi Valley Gas Company
dated November 1, 1993, as amended to extend
to March 31, 2005
10.13(l) Gas Transportation Agreement Contract No.
5151 between Tennessee Gas Pipeline and
Mississippi Valley Gas Company dated November
1, 1993, as amended to extend to November 30,
2006
Asset Purchase Agreements
10.14 Asset Purchase Agreement by and among Atmos Exhibit 10.1 to Registration Statement on
Energy Corporation, Atmos Energy Marketing Form S-3/A filed November 6, 2000 (File No.
LLC, Woodward Marketing, Inc., JD and Linda 333-93705)
Woodward and James and Rita B. Kifer dated as
of August 7, 2000
Executive Compensation Plans and Arrangements
10.15(a)* Form of Atmos Energy Corporation Change in Exhibit 10.21(b) of Form 10-K for fiscal
Control Severance Agreement -- Tier I year ended September 30, 1998 (File No.
1-10042)
10.15(b)* Form of Atmos Energy Corporation Change in Exhibit 10.21(c) of Form 10-K for fiscal
Control Severance Agreement -- Tier II year ended September 30, 1998 (File No.
1-10042)
10.16* Atmos Energy Corporation Long-Term Stock Plan Exhibit 99.1 of Form S-8 filed July 29, 1997
for the United Cities Gas Company Division (File No. 333-32343)
10.17(a)* Atmos Energy Corporation Executive Retiree Exhibit 10.31 of Form 10-K for fiscal year
Life Plan ended September 30, 1997 (File No. 1-10042)
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.17(b)* Amendment No. 1 to the Atmos Energy Exhibit 10.31(a) of Form 10-K for fiscal
Corporation Executive Retiree Life Plan year ended September 30, 1997 (File No.
1-10042)
10.18(a)* Description of Financial and Estate Planning Exhibit 10.25(b) of Form 10-K for fiscal
Program year ended September 30, 1997 (File No.
1-10042)
10.18(b)* Description of Sporting Events Program Exhibit 10.26(c) of Form 10-K for fiscal
year ended September 30, 1993 (File No.
1-10042)
10.19(a)* Atmos Energy Corporation Supplemental Exhibit 10.26 of Form 10-K for fiscal year
Executive Benefits Plan, Amended and Restated ended September 30, 1998 (File No. 1-10042)
in its Entirety: August 12, 1998
10.19(b)* Atmos Energy Corporation Performance-Based Exhibit 10.32 of Form 10-K for fiscal year
Supplemental Executive Benefits Plan, ended September 30, 1998 (File No. 1-10042)
Effective Date: August 12, 1998
10.19(c)* Amendment Number One to the Atmos Energy Exhibit 10.2 of Form 10-Q for quarter ended
Corporation Performance-Based Supplemental December 31, 2000 (File No. 1-10042)
Executive Benefits Plan, Effective Date:
January 1, 1999
10.19(d)* Atmos Energy Corporation Performance-Based Exhibit 10.1 of Form 10-Q for quarter ended
Supplemental Executive Benefits Plan Trust December 31, 2000 (File No. 1-10042)
Agreement, Effective Date December 1, 2000
10.19(e)* Form of Individual Trust Agreement for the Exhibit 10.3 of Form 10-Q for quarter ended
Supplemental Executive Benefits Plan December 31, 2000 (File No. 1-10042)
10.20* Atmos Energy Corporation Restricted Stock Exhibit 99.1 of Form S-8 filed February 13,
Grant Plan (Amended and Restated as of 1998 (File No. 333-46337)
February 12, 1998)
10.21* Atmos Energy Corporation Executive Exhibit 10.33 of Form 10-K for fiscal year
Nonqualified Deferred Compensation Plan ended September 30, 1998 (File No. 1-10042)
10.22(a)* Consulting Agreement between the Company and Exhibit 10.2 of Form 10-Q for quarter ended
Charles K. Vaughan, effective October 1, 1994 June 30, 1997 (File No. 1-10042)
10.22(b)* Amendment No. 1 to Consulting Agreement Exhibit 10.3 of Form 10-Q for quarter ended
between the Company and Charles K. Vaughan, June 30, 1997 (File No. 1-10042)
dated May 14, 1997
10.22(c)* Amendment No. 2 to Consulting Agreement Exhibit 10.30(c) of Form 10-K for fiscal
between the Company and Charles K. Vaughan, year ended September 30, 1998 (File No.
dated August 12, 1998 1-10042)
10.22(d)* Amendment No. 3 to Consulting Agreement Exhibit 10.30(d) of Form 10-K for fiscal
between the Company and Charles K. Vaughan, year ended September 30, 1999 (File No.
dated November 10, 1999 1-10042)
10.22(e)* Amendment No. 4 to Consulting Agreement Exhibit 10.32(e) of Form 10-K for fiscal
between the Company and Charles K. Vaughan, year ended September 30, 2000 (File No.
dated November 9, 2000 1-10042)
10.22(f)* Mini-Med/Dental Benefit Extension Agreement Exhibit 10.28(f) of Form 10-K for fiscal
dated October 1, 1994 year ended September 30, 2001 (File No.
1-10042)
10.22(g)* Amendment No. 1 to Mini-Med/Dental Benefit Exhibit 10.28(g) of Form 10-K for fiscal
Extension Agreement dated August 14, 2001 year ended September 30, 2001 (File No.
1-10042)
10.22(h)* Amendment No. 2 to Mini-Med/Dental Benefit Exhibit 10.1 of Form 10-Q for quarter ended
Extension Agreement dated December 31, 2002 December 31, 2002 (File No. 1-10042)
|
EXHIBIT
NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO
------- --------------------------------------------- --------------------------------------------
10.23* Atmos Energy Corporation Equity Incentive and Exhibit C of Definitive Proxy Statement on
Deferred Compensation Plan for Non-Employee Schedule 14A filed December 30, 1998 (File
Directors No. 1-10042)
10.24(a)* Atmos Energy Corporation Retirement Plan for Exhibit 10(y) of Form 10-K for fiscal year
Outside Directors ended September 30, 1992 (File No. 1-10042)
10.24(b)* Amendment No. 1 to the Atmos Energy Exhibit 10.2 of Form 10-Q for quarter ended
Corporation Retirement Plan for Outside December 31, 1996 (File No. 1-10042)
Directors
10.25* Atmos Energy Corporation Outside Directors Exhibit 10.28 of Form 10-K for fiscal year
Stock-for-Fee Plan (Amended and Restated as ended September 30, 1997 (File No. 1-10042)
of November 12, 1997)
10.26(a)* Atmos Energy Corporation 1998 Long-Term Exhibit 10.1 of Form 10-Q for quarter ended
Incentive Plan (as amended and restated March 31, 2002 (File No. 1-10042)
February 14, 2002)
10.26(b)* Atmos Energy Corporation Annual Incentive Exhibit 10.2 of Form 10-Q for quarter ended
Plan for Management (as amended and restated March 31, 2002 (File No. 1-10042)
February 14, 2002)
11 Not applicable
12 Computation of ratio of earnings to fixed
charges
13 Not applicable
16 Not applicable
18 Not applicable
Other Exhibits, as indicated
21 Subsidiaries of the registrant
22 Not applicable
23 Consent of independent auditor, Ernst & Young
LLP
24 Power of Attorney Signature page of Form 10-K for fiscal year
ended September 30, 2003
31 Certifications by the Company's Chief
Executive Officer and Chief Financial Officer
required by Rule 13a-14(a) Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
32.1 Certification Pursuant to 18 U.S.C Section
1350 as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 by the
Company's Chief Executive Officer**
32.2 Certification Pursuant to 18 U.S.C Section
1350 as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 by the
Company's Chief Financial Officer**
99 Annual Certification Pursuant to Section
303A.12 of the New York Stock Exchange Listed
Company Manual
|
* This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement."
** These certifications pursuant to 18 U.S.C. Section 1350 by the Company's Chief Executive Officer and Chief Financial Officer, furnished as Exhibits 32.1 and 32.2, respectively, to this Annual Report on Form 10-K, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.
RESOLVED, that the first sentence of Section 10.01 of the Bylaws of the
Company (as Amended and Restated as of November 12, 1997) shall be, and hereby
is, deleted and replaced in its entirety with the following:
10.01 Certificates Representing Shares. Unless the Articles of
Incorporation or these Bylaws provides otherwise, the Board of
Directors may provide by resolution the issue of some or all of the
shares of any or all of its classes or series with or without
certificates, provided that such resolution shall not apply to shares
represented by a certificate until such certificate is surrendered to
the corporation. Unless the Texas Business Corporation Act or the
Virginia Stock Corporation Act provides otherwise, there shall be no
differences in the rights and obligations of shareholders based on
whether or not their shares are represented by certificates. In the
event that the Board of Directors authorizes shares with certificates,
the corporation shall deliver certificates representing all shares to
which shareholders are entitled.
and;
FURTHER RESOLVED, that the third sentence of Section 10.01 of the
Bylaws of the Company shall be, and hereby is, deleted and replaced in its
entirety with the following:
The signatures of the Chairman of the Board, President, or Vice
President, and the Secretary or Assistant Secretary, upon a certificate
may be facsimiles, if the certificate is countersigned by a transfer
agent or registered by a registrar, which may also be facsimiles,
either of which is other than the corporation itself or an employee of
the corporation.
This SIXTH AMENDMENT TO CREDIT AGREEMENT, GLOBAL AMENDMENT TO LOAN DOCUMENTS AND WAIVER (this "Amendment") is entered into effective as of October 1, 2003, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002 (as amended, supplemented or otherwise modified prior to the date hereof, the "Credit Agreement") by and among WOODWARD MARKETING, L.L.C., a Delaware limited liability company (the "Borrower"), the financial institutions parties thereto (the "Banks"), FORTIS CAPITAL CORP., a Connecticut corporation ("Fortis"), as a Bank, as an Issuing Bank, as Collateral Agent and as Administrative Agent for the Banks, and BNP PARIBAS, a bank organized under the laws of France ("BNP Paribas"), as a Bank, as an Issuing Bank, and as Documentation Agent.
WHEREAS, the Borrower has requested that the Administrative
Agent and each of the Banks agree to waive any Default or Event of Default which
may exist under Section 8.02 of the Credit Agreement based solely upon (i)
Southern Resources, Inc., a Kentucky corporation ("Southern") and a Subsidiary
of the Borrower, merging with and into the Borrower, (ii) Trans Louisiana
Industrial Gas Company, Inc., a Delaware corporation ("TLIG") and a Subsidiary
of Atmos Energy Marketing, LLC, a Delaware limited liability company ("AEM"),
merging with and into AEM, (iii) AEM merging with and into the Borrower, (iv)
the existing Guaranty of AEM being concurrently released upon the effective time
of such merger, and (v) the Borrower changing its name to "Atmos Energy
Marketing, LLC" (the transaction described in the foregoing clauses (i) through
(v), the "Restructuring Transaction").
WHEREAS, the Borrower has requested that the Administrative Agent and the Banks agree to amend certain provisions of the Credit Agreement, as more fully set forth herein, in connection with the Restructuring Transaction; and
WHEREAS, the Administrative Agent and the Banks are willing to agree to such waivers and amendments, but only on the terms and subject to the conditions set forth in this Amendment;
NOW, THEREFORE, in consideration of premises and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Borrower, Fortis, BNP Paribas and the other Banks agree as follows:
1. Defined Terms. Unless otherwise defined herein, terms defined in the Credit Agreement are used herein as therein defined.
"Guarantor" means Atmos Energy Holdings, Inc."
and (c) all references in the Credit Agreement and in each other Loan Document to "Guarantors" shall be deleted and replaced with "Guarantor", and such conforming changes shall be made in such Loan Documents to reflect such change in number.
3. Waiver. The Administrative Agent and each of the
Banks hereby waive any Default or Event of Default which may exist under Section
8.02 of the Credit Agreement based solely upon the occurrence of the
Restructuring Transaction.
4. Representations. To induce the Administrative Agent and the Banks to enter into this Amendment, Borrower ratifies and confirms each representation and warranty set forth in the Credit Agreement as if such representations and warranties were made on even date herewith, and further represents and warrants (a) that no material adverse change has occurred in the financial condition or business prospects of Borrower since the date of the last financial statements delivered to the Administrative Agent and the Banks, (b) that, other than the violations of Section 8.02 of the Credit Agreement described in this Amendment, which violations have been waived by the Administrative Agent and each of the Banks in Section 3 herein, no Event of Default exists and no event or condition exists or has occurred which with passage of time, or notice, or both, would become an Event of Default (a "Default"), and (c) that Borrower is fully authorized to enter into this Amendment. BORROWER ACKNOWLEDGES THAT THE CREDIT AGREEMENT PROVIDES FOR A CREDIT FACILITY THAT IS COMPLETELY OPTIONAL ON THE PART OF THE BANKS AND THAT THE BANKS HAVE ABSOLUTELY NO DUTY OR OBLIGATION TO ADVANCE ANY REVOLVING LOAN OR TO ISSUE ANY LETTER OF CREDIT. BORROWER REPRESENTS AND WARRANTS TO THE BANKS THAT BORROWER IS AWARE OF THE RISKS ASSOCIATED WITH CONDUCTING BUSINESS UTILIZING AN UNCOMMITTED FACILITY.
5. Conditions Precedent. This Amendment shall become effective, with effect as of October 1, 2003, upon the Administrative Agent and the Banks having received:
(a) Payment of all fees and expenses owed to them on October 1, 2003; and
(i) this Amendment, duly executed by Borrower and the Banks;
(ii) amended and restated Notes of the Borrower, duly executed by the Borrower;
(iii) an amendment to the Guaranty, in form and substance satisfactory to the Administrative Agent and the Lenders;
(iv) copies of the resolutions of the members of the Borrower authorizing the transactions contemplated hereby and by the Credit Agreement, certified as of the date hereof by the Secretary of the Borrower, and certifying the names and true signatures of the officers of the Borrower authorized to execute, deliver and perform, as applicable, this Amendment and the other Loan Documents;
(v) copies of the documents and instruments entered into in connection with the Restructuring Transaction, certified as of the date hereof by a Secretary of the Borrower;
(vi) evidence satisfactory to the Administrative Agent that the Restructuring Transaction shall have occurred;
(vii) the certificate of formation and the operating agreement of the Borrower as in effect after giving effect to the Restructuring Transaction, all certified by the Secretary of the Borrower as of the date hereof, together with certificates of existence and good standing for the Borrower from the Secretary of State (or similar, applicable Governmental Authority) of its state of formation and each state where the Borrower is qualified to do business, certified as of the date hereof;
(viii) an amendment to the financing statement of the Borrower in favor of the Administrative Agent as secured party for the benefit of the Banks, amending the name of the Borrower as provided herein, and evidence that all other filings or actions needed to maintain the perfection of the security interests granted by the Security Agreements have been completed or due provision has been made therefor;
(ix) evidence of insurance required to be maintained by the Borrower under the Credit Agreement, reflecting the Borrower's name as amended herein; and
Upon the satisfaction of the foregoing conditions precedent, including without limitation an instrument executed and delivered by the Borrower expressly confirming the Borrower's assumption of all obligations of AEM in respect of the Loan Documents upon the effective time of the merger of AEM into the Borrower, the Guaranty of AEM shall be released without further action of any Person.
6. Miscellaneous.
(a) No Other Amendments or Waivers. Except as expressly consented to hereby, the Credit Agreement and the other Loan Documents shall remain in full force and effect in accordance with their respective terms, without any consent, amendment, waiver or modification of any provision thereof.
(b) Severability. In case any of the provisions of this Amendment shall for any reason be held to be invalid, illegal, or unenforceable, such invalidity, illegality, or unenforceability shall not affect any other provision hereof, and this Amendment shall be construed as if such invalid, illegal, or unenforceable provision had never been contained herein.
(c) Execution in Counterparts. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any party hereto may execute this Amendment by signing one or more counterparts. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of an originally executed counterpart of this Amendment.
(d) Governing Law. This Amendment shall be construed in accordance with and governed by the laws of the State of New York (without reference to principles of conflicts of laws); provided, however, that the Administrative Agent, the Banks and all Agent-Related Persons shall retain all rights under federal law.
(e) Rights of Third Parties. All provisions herein are imposed solely and exclusively for the benefit of Borrower, Administrative Agent, the Banks, Agent-Related Persons, and their permitted successors and assigns, and no other Person shall be a direct or indirect legal beneficiary of, or have any direct or indirect cause of action or claim in connection with this Amendment or any of the other Loan Documents.
(f) COMPLETE AGREEMENT. THIS WRITTEN AMENDMENT AND THE OTHER WRITTEN AGREEMENTS ENTERED INTO AMONG THE PARTIES REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF
By: /s/ Richard C. Alford
----------------------------------
Name: Richard C. Alford
Title: Senior Vice President
|
Borrower's Address:
By: /s/ Irene Rummel
---------------------------------
Name: Irene Rummel
Title: Senior Vice President
By: /s/ Chad Clark
---------------------------------
Name: Chad Clark
Title: Vice President
|
15455 N. Dallas Parkway Suite 1400 Dallas, TX 75001 Telephone: (214) 953-9313 Facsimile: (214) 969-9332
[Signatures continue on following page.]
[Amendment to Credit Agreement]
By: /s/ Edward K. Chin
----------------------------------
Name: Edward K. Chin
Title: Director
By: /s/ Zali Win
----------------------------------
Name: Zali Win
Title: Director
|
787 Seventh Avenue New York, New York 10019 Attention: Ed Chin Telephone: (212) 841-2020 Facsimile: (212) 841-2536
[Signatures continue on following page.]
[Amendment to Credit Agreement]
By: /s/ Barbara Paulsen
----------------------------------
Name: Barbara Paulsen
Title: Vice President
By: /s/ Emmanuel Chesneau
----------------------------------
Name: Emmanuel Chesneau
Title: Director
|
1221 Avenue of the Americas New York, New York 10020 Attention: Barbara Paulsen Telephone: (212) 278-6496 Facsimile: (212) 278-7417
[Signatures continue on following page.]
[Amendment to Credit Agreement]
By: /s/ David Pershad
----------------------
Name: David Perhad
Title: Vice President
By: /s/ Guillaume de Parscau
----------------------------
Name: Guillaume de Parscau
Title: First Vice President &
Manager, Commodities Finance
Group
|
1251 Avenue of the Americas, 34th Floor New York, New York 10020 Attention: David Pershad Telephone: (212) 872-5015 Facsimile: (212) 354-9095
By: /s/ Frank J.Yautz
------------------------
Name: Frank J. Yautz
Title: First Vice President
By: /s/ Pearl Geffers
-------------------------
Name: Pearl Geffers
Title: First Vice President
|
1133 Avenue of the Americas New York, New York 10036 Attention: Hermine Kirolos Telephone: (212) 845-4114 Facsimile: (212) 944-6389
[Signatures continue on following page.]
[Amendment to Credit Agreement]
By: /s/ Ronald W. Bahr
------------------------
Name: Ronald W. Bahr
Title: Vice President
|
1800 Three Lincoln Centre 5430 LBJ Freeway Dallas, TX 75240
[Amendment to Credit Agreement]
THIS SERVICE AGREEMENT (Agreement), made and entered into as of this 1st day of May, 2003, by and between Public Service Company of Colorado (Company), a Colorado corporation, having a mailing address of P.O. Box 840, Denver, Colorado, 80202, and Atmos Energy Corporation (Shipper), a Texas corporation, having a mailing address of 700 Three Lincoln Centre, 5430 LBJ Freeway, P.O. Box 650205, Dallas, Texas 75265-0205. Company and Shipper are collectively referred to as the "Parties."
Shipper has by separate agreement acquired supplies of natural gas, hereinafter referred to as "Shipper's Gas;"
Shipper has made the necessary arrangements and/or has entered into separate agreements to cause Shipper's Gas to be delivered to Company's Receipt Point(s) as specified in Exhibit(s) "A- 1" through "C-2;"
Shipper has requested and Company agrees to receive and transport Shipper's Gas from the Receipt Point(s) to the Delivery Point(s), as specified in Exhibit(s) "A-l" through "C-2," on a firm capacity basis and, if applicable, to sell gas to Shipper on a firm supply reservation basis; and
Shipper assumes responsibility for the installation and maintenance costs for a communication line necessary for electronic metering for the facility(s) specified in Exhibit(s) "A-1," "B-1" and "C-1."
1. Shipper acknowledges and agrees that gas transportation service provided hereunder is subject to the terms and conditions of Company's applicable gas transportation tariff as on file and in effect from time to time with the Public Utilities Commission of the State of Colorado (Commission) and such terms and conditions are incorporated herein as part of this Agreement.
2. Rates and Payment: Transportation service, Firm Capacity service and Firm Supply Reservation service provided by Company under this Service Agreement shall be paid for by Shipper at the charges under the standard rate set forth in Company's gas transportation tariff unless otherwise specified in Exhibit(s) "A-l" through "C-2." Applicable facility charges shall be paid at the rate set forth in Company's Gas Transportation Tariff unless otherwise specified in Exhibit(s) "A-l" through "C-2."
3. Back-up Supply Sales Service: In the event that adequate supplies of Shipper's gas are not available for receipt by Company, Company shall sell to Shipper sufficient quantity(s) of
4. Quality: Gas delivered by the Shipper or for the Shipper's account at the Receipt Point(s) as specified in Exhibit(s) "A-l" through "C-2" shall conform to the specifications for gas as specified in Exhibit "D" and Exhibit "E."
5. Term - Effective Date: Service hereunder shall commence effective May 1, 2003 and, unless otherwise mutually agreed, shall continue through April 30, 2005 and from year to year thereafter until terminated by either party effective upon the expiration of the initial term or May 1 of any succeeding year upon six (6) months written notice.
6. Notices: Except as otherwise provided, any notice or information that either party may desire to give to the other regarding this agreement shall be in writing to the following address, or to such other address as either of the parties shall designate in writing.
COMPANY: SHIPPER:
Payments Only: Atmos Energy Corporation
Xcel Energy P.O. Box 650205
P.O. Box 9477 Dallas, Texas 75265-0205
Denver, Colorado 80217-0230 Invoices only:
Phone: (303)623-1234 Attn: Gas Purchase Accounting Dept.
Fax: (303)294-2136 Phone: (972)855-3296
Fax: (214)550-9369
Contracts and Notices:
Attn: Contract Administration
Phone: (972)855-3753
Fax: (972)855-3773
E-Mail Capacity Overrun Notification:
Attn: Phil Davis
Phillip.Davis@atmosenergy.com
All Others:
Xcel Energy All Others:
550 15th Street Atmos Energy Corporation
Suite 500 Attn: Gas Supply Dept
Denver, Colorado 80202 1301 Pennsylvania, Suite 800
Attn: Unit Manager, Gas Transportation Denver, Colorado 80203-5014
Phone: (303)294-8318 Phone: (303)831-5667
Fax: (303)294-2757 Fax: (303)831-9549
7. Assignment - Consent: This Service Agreement shall not be assigned by either party hereto without the prior written consent of the other party. Consent for assignment of this Service Agreement shall not be unreasonably withheld by or from either party.
8. Cancellation of Prior Agreement: This Service Agreement supersedes, cancels and terminates, as of the date of this Service Agreement, the following agreements and any amendments thereto:
Gas Transportation Service Agreement, dated 11/1/98 (Document No. 123535), between Greeley Gas Company, a division of Atmos Energy Company and Public Service Company of Colorado
9. Maximum Capacity by Zone:
(a) Administrative circumstances require the separation of electronically metered and non-electronically metered volumes into two separate Exhibits covering the same regional area, as reflected in the attached Exhibit "A-l" (Electronically Metered Front Range) and Exhibit "A-2" (Non-Electronically Metered Front Range), Exhibit "B-l" (Electronically Metered Southern) and Exhibit "B-2" (Non-Electronically Metered Southern(, and Exhibit "C-l" (Electronically Metered Western) and Exhibit "C-2" (Non-Electronically Metered Western). When electronic measurement facilities are installed and their proper operation is mutually agreed to by both parties for any Delivery Point identified on any Non-Electronically Metered Exhibit A-2, B-2 and C-2 attached hereto, such Delivery Point, its associated Peak Day Quantity and allocable Receipt Point Capacity shall be transferred to the applicable Electronically Metered Exhibit effective the first day of the following month.
(b) Transporter shall make available firm transportation service hereunder up to the maximum contracted volume by Zone reflected on Exhibits A-3, B-3 and C-3 attached hereto. A Zone is an operationally contiguous segment of Company's delivery system within an Exhibit area. A Zone may contain Delivery Points from both Electronically and Non-Electronically Metered Exhibits, i.e., the Front Range Area Zones 1,2,3,4 and 5, comprised of Delivery Points under Exhibits "A-l" and "A-2", the Southern Area Zones 1, 2 and 3, comprised of Delivery Points under Exhibit "B-l" and "B-2", and the Western Area Zones 1, 2 and 3, comprised of Delivery Points under Exhibits "C-1" and "C-2". Exhibits A-3, B-3 and C-3 attached hereto identify the Zones and associated Delivery Point and Peak Day Quantities available to Shipper hereunder.
10. Delivery Point Peak Day Quantity:
(a) The Delivery Points reflected in the attached Exhibits "A-l" through "C-2" are interconnections between Company's pipeline system and Shipper's downstream natural gas facilities and the parties recognize the mutual operational benefits of providing for flexibility in coordinating gas flows at each of these Delivery Points. The Peak Day Quantities identified in the attached Exhibits "A-l" through "C-2" represent Shipper's current and best information of
(b) (i) On a monthly basis, Company will review the actual deliveries made to these points and, provided the total volumes delivered within a Zone do not exceed the total contracted-for volume applicable to the corresponding Delivery Points within the Zone, Company will authorize any volume exceeding the Delivery Point Peak Day Quantity as authorized overrun gas; provided, however, in no event shall any volume at any Delivery Point ever exceed the design capacity of Company's facilities for such point. Should delivered volumes at any Delivery Point consistently exceed the Peak Day Quantity for that point, Shipper will request and Company will accept, subject to available capacity, an increase in the contracted-for Peak Day Quantity at the specified Delivery Point. In increasing the contracted volume at a Delivery Point, Shipper may shift volumes from other Delivery Point(s) within the same Zone if volumes delivered at such other Delivery Point(s) do not exceed their established maximum Peak Day Quantities. During quarterly meetings, Company and Shipper shall review Delivery Points which have exceeded Peak Day Quantities and, if the Parties agree that such overrun(s) are recurring or are expected to be recurring, Shipper shall request an increase to the Delivery Point Peak Day Quantity.
(ii) If on any day total deliveries within a Zone exceed the combined Peak Day Quantities of Delivery Points within the Zone, Company shall provide Shipper with written notification of such overrun and, subject to available capacity, the increase in Delivery Point Peak Day Quantity(s) that will be implemented to increase the Zone combined Peak Day Quantities to the actual maximum day usage. Within ten business days following such written notification, Shipper may request and Company will authorize, subject to available capacity, revision(s) in the Peak Day Quantity(s) for the Delivery Point(s) identified by the Company in said notification in order that the combined Zone Peak Day Quantity shall be equal to the maximum daily usage experienced for that Zone. Unless otherwise agreed to by the parties, the new Peak Day Quantities shall become effective the first day of the month following the month in which the Zone overrun occurred. If Company, in its sole opinion, determines that sufficient firm capacity is unavailable for any such requested increase, then Company shall provide written notification to Shipper of the Company's denial of Shipper's requested increase of firm capacity. Any unauthorized quantities in excess of the maximum Zone capacity occurring after such written notification shall be deemed unauthorized overrun gas, subject to unauthorized overrun capacity charges as set forth in Company's tariff.
(c) If, pursuant to any applicable state law or administrative action, order, or regulation Shipper restructures its gas utility services to provide unbundled gas sales and transportation services to some or all of its customers, and such restructuring results in Shipper holding Peak Day Quantities under this Agreement in excess of that required to provide service to the markets served by Shipper using the gas transportation service provided under this Agreement subsequent to such restructuring ("Excess Capacity"), Shipper shall have the right to reduce the Peak Day Quantities hereunder by the quantity of such Excess Capacity to the extent Shipper is unable,
11. Because daily usage information is unavailable until the succeeding month for non-electronically metered Delivery Points, for all Delivery Points listed on Exhibits "A-2," "B-2" and "C-2," Shipper will nominate transportation volumes based on all infonnation Shipper deems appropriate including but not limited to historic usage information and projected load requirements utilizing anticipated weather conditions. Therefore, imbalances accrued with respect to such non-electronically metered Delivery Points are exempt from only the current-month balancing provisions of Company's Tariff as they would apply to this Agreement, so long as there is no determination by the Colorado Public Utilities Commission that such an exemption is unlawful.
12. Exhibit(s) and Addendums: All exhibits attached hereto are incorporated into the terms of this Agreement.
13. This Agreement shall be governed by and construed in accordance with the laws of the State of Colorado.
IN WITNESS WHEREOF, the parties have executed this Firm Gas Transportation Service Agreement as of the day and year first above written.
COMPANY: SHIPPER:
PUBLIC SERVICE COMPANY ATMOS ENERGY CORPORATION
OF COLORADO
/s/ Cynthia A. Evans /s/ Gary Schlessman
----------------------------------- -------------------------------------
By Cynthia A. Evans By Gary Schlessman
Vice President President, Colorado-Kansas Division
Reviewed
Legal
Taxpayer ID. No. 84-0296600 Taxpayer I.D. No. 75-1743247
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Contract No.: 123535
Effective Date Of Agreement: 5/01/2003
Effective Date of Exhibit: 5/01/2003
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1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity Dth/Day Utilization Curve
-------------------------------------------------------------------------------------------------
Front Range Pipeline - Owl Creek 16,540 General
CIG Ault 9,893 General
CIG Ft. Lupton 14,949 General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm
Capacity Service Transport-
Peak Day and ation
Quantity Facility Specific Commodity
Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate
-----------------------------------------------------------------------------------------------------------------------------
Platteville 906412745 609 TF N/A Standard 4/30/05
Monfort Meas Stat. 706412727 36 TF N/A Standard 4/30/05
Kersey Group 706412713 80 TF N/A Standard 4/30/05
Lasalle 406412719 702 TF N/A Standard 4/30/05
Ault #1 & #2 306412692 650 TF N/A Standard 4/30/05
North Greeley 106412730 10,300 TF N/A Standard 4/30/05
Promontory 770150163 693 TF N/A Standard 4/30/05
West Greeley 606412761 11,078 TF NA Standard 4/30/05
Lucerne #1 606412723 150 TF N/A Standard 4/30/05
South Greeley 106412754 10,100 TF N/A Standard 4/30/05
Eaton #1 & #2 206412763 3,800 TF N/A Standard 4/30/05
Total Firm Capacity Reservation Peak Day Quantity: 38,198 Dth
3. FIRM SUPPLY RESERVATION SERVICE
Total Firm Supply Reservation Quantity available for delivery to all of Shipper's Delivery Points as may be nominated from time to time under contract numbers 123535 and 177473: 3,005 Dth
1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
-------------------------------------------------------------------------------------------------
Front Range Pipeline-Owl Creek 3,460 General
CIG Ft Lupton 51 General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm
Capacity Service Transport-
Peak Day and ation
Quantity Facility Specific Commodity
Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate
-----------------------------------------------------------------------------------------------------------------------------
Keenesburg 306412710 353 TF N/A Standard 4/30/2005
Gilcrest 506412766 321 TF N/A Standard 4/30/2005
Prospect Valley 306412748 31 TF N/A Standard 4/30/2005
South Gate Trailer 106412768 54 TF N/A Standard 4/30/2005
South Roggen 106412773 5 TF N/A Standard 4/30/2005
Roggen 706412751 39 TF N/A Standard 4/30/2005
Nunn 206412739 151 TF N/A Standard 4/30/2005
West LaSalle Group 506412771 34 TF N/A Standard 4/30/2005
Hill-N-Park 206412697 293 TF N/A Standard 4/30/2005
Corsey Group 906412694 57 TF N/A Standard 4/30/2005
Pierce 606412742 349 TF N/A Standard 4/30/2005
Greeley Farm Taps 980121701 1000 N/A N/A Standard 4/30/2005
West Hudson 306412705 299 TF N/A Standard 4/30/2005
Hudson 406412700 338 TF N/A Standard 4/30/2005
East Keenesburg 606412695 48 TF N/A Standard 4/30/2005
Kersey Farm Taps TBD 20 N/A N/A Standard 4/30/2005
Gilcrest Farm Taps TBD 80 N/A N/A Standard 4/30/2005
Ault Farm Taps TBD 300 N/A N/A Standard 4/30/2005
Hudson Farm Taps TBD 30 N/A N/A Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 3,802 Dth
Firm Capacity
Peak Day
Zone Delivery Point(s) Load Point Quantity (Dth)
------------------------------------------------------------------------------
FR ZONE 1
Kersey Group 706412713 80
Kersey Farm Taps 20
TOTAL FR ZONE 1: 100
FR ZONE 2
West LaSalle Group 506412771 34
Lasalle 406412719 702
Platteville 906412745 609
Gilcrest 506412766 321
South Gate Trailer 106412768 54
Gilcrest Farm Taps 80
TOTAL FR ZONE 2: 1,800
FR ZONE 3
Monfort Meas Stat. 706412727 36
Hill-N-Park 206412697 293
North Greeley 106412730 10,300
West Greeley 606412761 11,078
South Greeley 106412754 10,100
Promontory 770150163 693
Greeley Farm Taps 980121701 1000
TOTAL FR ZONE 3: 33,500
EXHIBIT "A-3" - FRONT RANGE ZONES continued
Firm Capacity
Peak Day
Zone Delivery Point(s) Load Point Quantity (Dth)
----------------------------------------------------------------------------
FR ZONE 4
Lucerne #1 & #2 606412723 150
Eaton #1 & #2 206412763 3,800
Nunn 206412739 151
Ault #l & #2 306412692 650
Pierce 606412742 349
Ault Farm Taps 300
TOTAL FR ZONE 4: 5,400
FR ZONE 5
Prospect Valley 306412748 31
South Roggen 106412773 5
Roggen 706412751 39
Keenesburg 306412710 353
Corsey Group 906412694 57
West Hudson 306412705 299
Hudson 406412700 338
East Keenesburg 606412695 48
Hudson Farm Taps 30
TOTAL FR ZONE 5: 1,200
TOTAL FR ZONES 42,000
1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
-------------------------------------------------------------------------------------------------
Outlet of Tiffany Compressor Station 6,500 Stabilized
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm
Capacity Service Transport-
Peak Day and ation
Quantity Facility Specific Commodity
Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate
----------------------------------------------------------------------------------------------------------------------------
Chalk Creek 206412678 86 TF N/A Standard 4/30/2005
West Gunnison
Town Border 906412707 596 TF N/A Standard 4/30/2005
East Gunnison
Town Border Station 306412687 2,338 TF N/A Standard 4/30/2005
Salida Town Border
Station 206412701 2,523 TF N/A Standard 4/30/2005
Crested Butte Town
Border Station 406412639 754 TF N/A Standard 4/30/2005
Poncha Springs 706412690 108 TF N/A Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 6,405 Dth
1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
-------------------------------------------------------------------------------------------------
Outlet of Tiffany Compressor Station 807 Stabilized
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport-
Peak Day and ation
Quantity Facility Specific Commodity
Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate
---------------------------------------------------------------------------------------------------------------------------
Durango Farm Tap 660156934 1 N/A NA Standard 4/30/2005
Gunnison Farm Tap 606412681 150 N/A NA Standard 4/30/2005
Tomichi Village 106412706 29 TF NA Standard 4/30/2005
Salida Farm Taps 270039611 231 N/A NA Standard 4/30/2005
Crested Butte Farm Taps 806412642 260 N/A NA Standard 4/30/2005
Crested Butte South 960022981 124 TF NA Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 795 Dth
Firm Capacity
Peak Day
Zone Delivery Point(s) Load Point Quantity (Dth)
-----------------------------------------------------------------------------------------------
SO. ZONE 1
Crested Butte Town Border Station 406412639 754
Crested Butte South 960022981 124
Crested Butte Farm Taps 806412642 260
TOTAL SO. ZONE 1 : 1,138
SO. ZONE 2
West Gunnison Town Border 906412707 596
East Gunnison Town Border Station 306412687 2,338
Gunnison Farm Tap 606412681 150
Tomichi Village 106412706 29
TOTAL SO. ZONE 2: 3,113
SO. ZONE 3
Salida Town Border Station 206412701 2,523
Salida Farm Taps 270039611 231
Chalk Creek 206412678 86
Poncha Springs 706412690 108
Durango Farm Tap 660156934 1
TOTAL SO. ZONE 3: 2,949
TOTAL SO. ZONES: 7,200
1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve
----------------------------------------------------------------------
KNGWRD 680 General
MOFRRO 575 General
LONGCA 266 General
NF1GCA 1,770 General
NF1GHC 3,540 General
NF2GCA 3,540 General
ROSGCA 89 General
TERGCA 22 General
TWIGCA 66 General
CIG Ft Lupton General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport-
Peak Day and ation
Quantity Facility Specific Facility Commodity
Delivery Point(s) Load Point (Dth) Charge Charge Char