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Atmos Energy 10-K 2006 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Commission file number 1-10042
Registrant’s telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the
Act:
Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
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 þ No o
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. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the voting stock held by
non-affiliates of the registrant as of the last business day of
the registrant’s most recently completed second fiscal
quarter, March 31, 2006, was $2,064,662,421.
As of November 8, 2006, the registrant had
81,823,767 shares of common stock outstanding.
Portions of the registrant’s Definitive Proxy Statement to
be filed for the Annual Meeting of Shareholders on
February 7, 2007 are incorporated by reference into
Part III of this report.
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The terms “we,” “our,” “us,”
“Atmos” and “Atmos Energy” refer to Atmos
Energy Corporation and its subsidiaries, unless the context
suggests otherwise.
Atmos Energy Corporation, headquartered in Dallas, Texas, is
engaged primarily in the natural gas utility business as well as
other natural gas nonutility businesses. We are one of the
country’s largest natural-gas-only distributors based on
number of customers and one of the largest intrastate pipeline
operators in Texas based upon miles of pipe. As of
September 30, 2006, we distributed natural gas through
sales and transportation arrangements to approximately
3.2 million residential, commercial, public authority and
industrial customers through our seven regulated utility
divisions, which covered service areas in 12 states. Our
primary service areas are located in Colorado, Kansas, Kentucky,
Louisiana, Mississippi, Tennessee and Texas. We have more
limited service areas in Georgia, Illinois, Iowa, Missouri and
Virginia. In addition, we transport natural gas for others
through our distribution system.
Through our nonutility businesses, we primarily provide natural
gas management and marketing services to municipalities, other
local gas distribution companies and industrial customers in
22 states and natural gas transportation and storage
services to certain of our utility divisions and to third
parties.
We were organized under the laws of Texas in 1983 as Energas
Company for the purpose of owning and operating the natural gas
distribution business of Pioneer Corporation in Texas. In
September 1988, we changed our name to Atmos Energy Corporation.
As a result of the merger with United Cities Gas Company in July
1997, we also became incorporated in Virginia.
Our operations are divided into four segments:
Our overall strategy is to:
Over the last five years, we have primarily grown through two
significant acquisitions, our acquisition in December 2002 of
Mississippi Valley Gas Company (MVG) and our acquisition in
October 2004 of the natural gas distribution and pipeline
operations of TXU Gas Company (TXU Gas).
We have experienced over 20 consecutive years of increasing
dividends and earnings growth after giving effect to our
acquisitions. We have achieved this record of growth while
operating our utility operations efficiently by managing our
operating and maintenance expenses and leveraging our
technology, such as our
24-hour call
centers, to achieve more efficient operations. In addition, we
have focused on regulatory rate
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proceedings to increase revenue as our costs increase and
mitigated weather-related risks through weather-normalized rates
that now apply to most of our service areas. We have also
strengthened our nonutility businesses by increasing gross
profit margins, actively pursuing opportunities to increase the
amount of storage available to us and expanding commercial
opportunities in our pipeline and storage segment.
Our core values include focusing on our employees and customers
while conducting our business with honesty and integrity. We
continue to strengthen our culture through ongoing
communications with our employees and enhanced employee training.
Utility
Segment Overview
We operated our utility segment through the following seven
regulated natural gas utility divisions during the year ended
September 30, 2006:
Effective October 1, 2006, the Kentucky and Mid-States
Divisions were combined.
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.
In addition to weather, our financial results 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. Higher
gas costs may also adversely impact our accounts receivable
collections, resulting in higher bad debt expense and may
require us to increase borrowings under our credit facilities
resulting in higher interest expense.
The effect of weather that is above or below normal is
substantially offset through weather normalization adjustments,
known as WNA, which are now approved by the regulators for over
90 percent of residential and commercial meters in our
service areas. WNA allows us to increase customers’ bills
to offset lower gas usage when weather is warmer than normal and
decrease customers’ bills to offset higher gas usage when
weather is colder than normal.
Prior to October 1, 2006, our largest division, the Mid-Tex
Division, did not have WNA. However, its operations benefited
from a rate structure that combined a monthly customer charge
with a declining block rate schedule to partially mitigate the
impact of
warmer-than-normal
weather on revenue. The combination of the monthly customer
charge and the customer billing under the first block of the
declining block rate schedule provided for the recovery of most
of our fixed costs for such operations under most weather
conditions. However, this rate structure was not as beneficial
during periods where weather was significantly warmer than
normal.
In May 2006, the Mid-Tex Division filed a Statement of Intent
seeking additional annual revenues of $60 million and
several rate design changes including WNA. In July 2006, the
Railroad Commission of Texas
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(RRC) approved an interim and a permanent WNA, effective
October 1, 2006 for the Mid-Tex Division. The agreement
provided that the interim WNA will be based on the use of
30 years of weather history, while the permanent WNA will
allow the parties to contest the appropriate period of weather
data to use in calculating normal weather. The permanent WNA
will also be modified or adjusted to conform to the rate design
that the RRC ultimately approves in the case. Additionally, in
May 2006, we agreed to a settlement with the Louisiana Public
Service Commission (LPSC) that authorized the implementation of
WNA in our Louisiana Division effective December 1, 2006.
As of September 30, 2006 we had, or received regulatory
approvals for WNA for our customer meters in the following
service areas for the following periods:
Our natural gas supply comes from a variety of third-party
providers and from gas held in storage. We anticipate that the
natural gas supply for the upcoming winter heating season will
be provided by a variety of suppliers, including independent
producers, marketers and pipeline companies, in addition to
withdrawals of gas from storage. Additionally, the natural gas
supply for our Mid-Tex Division includes peaking and spot
purchase agreements. We also contract for storage service in
underground storage facilities on many of the interstate
pipelines serving us. We estimate the peak-day availability of
natural gas supply from long-term contracts, short-term
contracts and withdrawals from underground storage to be
approximately 4.2 Bcf. The peak-day demand for our utility
operations in fiscal 2006 was on December 8, 2005, when
sales to customers reached approximately 3.4 Bcf.
Supply arrangements are contracted from our suppliers 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. Major suppliers during fiscal 2006
were Anadarko Energy Services, BP Energy Company, Chesapeake
Energy Marketing, Inc., ConocoPhillips Company, Cross Timbers
Energy Services, Inc., Devon Gas Services, L.P., Enbridge
Marketing (US) L.P., PPM Energy, Inc., Tenaska Marketing and
Atmos Energy Marketing, LLC, our natural gas marketing
subsidiary.
The combination of base load, peaking and spot purchase
agreements, coupled with the withdrawal of gas held in storage,
allows us the flexibility to adjust to changes in weather, which
minimizes our need to enter into long-term firm commitments.
Also, 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 or applicable state statutes or regulations. Our
customers’ demand on our system is not necessarily
indicative of our ability to
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meet current or anticipated market demands or immediate delivery
requirements because of factors such as the physical limitations
of gathering, storage and transmission systems, the duration and
severity of cold weather, the availability of gas reserves from
our suppliers, the ability to purchase additional supplies on a
short-term basis and actions by federal and state regulatory
authorities. Curtailment rights provide us the flexibility to
meet the human-needs requirements of our customers on a firm
basis. Priority allocations imposed by federal and state
regulatory agencies, as well as other factors beyond our
control, may affect our ability to meet the demands of our
customers. We anticipate no problems with obtaining additional
gas supply as needed for our customers.
We receive gas deliveries for all of our utility divisions,
except for our Mid-Tex Division, through 37 pipeline
transportation companies, both interstate and intrastate, to
satisfy our natural gas needs. 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. The natural gas supply for our Mid-Tex Division
is delivered by our Atmos Pipeline — Texas Division.
The following is a brief description of our seven natural gas
utility divisions. Additional information for our natural gas
utility divisions 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. Rates in our Kansas
service area are subject to WNA. The principal transporters of
the Colorado-Kansas Division’s gas supply requirements are
Colorado Interstate Gas Company, Northwest Pipeline, Public
Service Company of Colorado and Southern Star Central Pipeline.
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 (KPSC), which regulates utility
services, rates, issuance of securities and other matters. We
operate in various incorporated cities pursuant to non-exclusive
franchises granted by these cities. The sale of natural gas for
use as vehicle fuel in Kentucky is unregulated. In February
2006, the KPSC approved our request to continue the
performance-based ratemaking mechanism for an additional
five-year period. Under the performance-based mechanism, 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 Midwestern Pipeline, Tennessee Gas
Pipeline Company, Texas Gas Transmission LLC and Trunkline Gas
Company. As noted below, this division was combined with the
Mid-States Division effective October 1, 2006.
Atmos Energy Louisiana Division. Our Louisiana
Division operates in Louisiana and serves the metropolitan area
of Monroe, the suburban areas of New Orleans and western
Louisiana. 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 and are recognized in our
natural gas marketing segment. Effective beginning with the
2006-2007
winter heating season, rates in our Louisiana service area will
be subject to WNA. The principal transporters of the Louisiana
Division’s gas supply requirements are Acadian Pipeline,
Gulf South, Louisiana Intrastate Gas Company, Texas Gas
Transmission LLC and Trans Louisiana Gas Pipeline, Inc., a
subsidiary of Atmos Pipeline and Storage, LLC.
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 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
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for us to find ways to lower costs and share the cost savings
with our customers. We have WNA in our Virginia service area
that covers the entire year. Our Mid-States Division is served
by 13 interstate pipelines; however, the majority of the volumes
are transported through Columbia Gulf, East Tennessee Pipeline,
Southern Natural Gas and Tennessee Gas Pipeline. The Kentucky
Division was combined with the Mid-States Division effective
October 1, 2006.
Atmos Energy Mid-Tex Division. Our Mid-Tex
Division includes the natural gas distribution operations that
operate in the north-central, eastern and western parts of
Texas. The Mid-Tex Division purchases, distributes and sells
natural gas in approximately 550 cities and towns,
including the 11-county Dallas/Fort Worth metropolitan
area. This division currently operates under a system-wide rate
structure. 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 RRC 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.
Effective beginning with the
2006-2007
winter heating season, rates in our Mid-Tex service area will be
subject to WNA.
Atmos Energy Mississippi Division. Our Atmos
Energy Mississippi Division operates in Mississippi and is
regulated by the Mississippi Public Service Commission (MPSC)
with respect to rates, services and operations. We operate under
non-exclusive franchises granted by the municipalities we serve.
Through fiscal 2005, we operated under a rate structure that
allowed us, over a five-year period, to recover a portion of our
integration costs associated with the MVG acquisition and
operations and maintenance costs in excess of an agreed-upon
benchmark. In addition, we were required to file for rate
adjustments based on our expenses every six months. Effective
October 1, 2005, our rate design was modified to substitute
the original agreed-upon benchmark with a sharing mechanism to
allow the sharing of cost savings above an allowed return on
equity level. Further, beginning October 1, 2005, we moved
from a semi-annual filing process to an annual filing process.
We also have WNA in Mississippi. This division’s gas supply
is delivered primarily 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.
Atmos Energy West Texas Division. Our West
Texas Division operates in Texas in three primary service areas:
the Amarillo service area, the Lubbock service area and the West
Texas service area. Similar to our Mid-Tex Division, 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 RRC
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. We
have WNA in each of our service areas. Our West Texas Division
receives transportation service from ONEOK Pipeline. In
addition, the West 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.
Our natural gas marketing and other nonutility segments, which
are organized under Atmos Energy Holdings, Inc. (AEH), have
operations in 22 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 Energy
and United Cities Gas Company, which had acquired that interest
in May 1995. In April
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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 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. We use proprietary and customer-owned
transportation and storage assets to provide the various
services our customers request. As a result, our revenues arise
from the types of commercial transactions we have structured
with our customers and include the value we extract by
optimizing the storage and transportation capacity we own or
control as well as revenues for services we deliver.
We participate in transactions in which we combine the natural
gas commodity and transportation costs to minimize our costs
incurred to serve our customers. Additionally, we participate in
natural gas storage transactions in which we seek to capture the
pricing differences that occur over time. We purchase physical
natural gas and then sell financial contracts at favorable
prices to lock in a gross profit margin. Through the use of
transportation and storage services and derivatives, we are able
to capture gross profit margin through the arbitrage of pricing
differences in various locations and by recognizing pricing
differences that occur over time.
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. 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. At
September 30, 2006, AEM had a total of 679 industrial, 73
municipal and 289 other customers.
Our pipeline and storage segment consists of the regulated
pipeline and storage operations of the Atmos
Pipeline — Texas Division and the nonregulated
pipeline and storage operations of Atmos Pipeline and Storage,
LLC (APS). The Atmos Pipeline — Texas Division
transports natural gas to our Mid-Tex Division, transports
natural gas for third parties and manages five underground
storage reservoirs in Texas. We also provide ancillary services
customary in the pipeline industry including parking
arrangements, lending and sales of inventory on hand. Parking
arrangements provide short-term interruptible storage of gas on
our pipeline and lending services provide short-term
interruptible loans of natural gas from our pipeline to meet
market demands. Both of these services are primarily offered on
our Atmos Pipeline — Texas system. These operations
represent one of the largest intrastate pipeline operations in
Texas with a heavy concentration in the established natural
gas-producing areas of central, northern and eastern Texas,
extending into or near the major producing areas of the Texas
Gulf Coast and the Delaware and Val Verde Basins of West Texas.
Nine basins located in Texas are believed to contain a
substantial portion of the nation’s remaining onshore
natural gas reserves. This pipeline system provides access to
all of these basins.
APS owns or has an interest in underground storage fields in
Kentucky and Louisiana. We also use these storage facilities to
reduce the need to contract for additional pipeline capacity to
meet customer demand during peak periods.
In May 2006, APS announced plans to form a joint venture with a
local natural gas producer to construct a natural gas gathering
system in Eastern Kentucky. Referred to as the Straight Creek
Project, the new system is expected to relieve severe gas
gathering and transportation constraints that historically have
burdened natural gas producers in the area and should improve
delivery reliability to natural gas customers. In October 2006,
the Federal Energy Regulatory Commission (FERC) issued a
declaratory order finding that the Straight Creek Project will
be exempt from FERC jurisdiction. The joint venture provides APS
the opportunity to apply its expertise to the upstream gathering
business.
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Our other nonutility segment consists primarily of the
operations of Atmos Energy Services, LLC (AES), and Atmos Power
Systems, Inc. which are wholly-owned by our subsidiary, Atmos
Energy Holdings, Inc. Through AES, we provide natural gas
management services to our utility operations, other than the
Mid-Tex Division. These services, which began in April 2004,
include aggregating and purchasing gas supply, arranging
transportation and storage logistics and ultimately delivering
the gas to our utility service areas at competitive prices in
exchange for revenues that are equal to the costs incurred to
provide those services. Through Atmos Power Systems, Inc., we
have constructed electric peaking power-generating plants and
associated facilities and have entered into agreements to lease
these plants.
Through January 2004, United Cities Propane Gas, Inc., a
wholly-owned subsidiary of Atmos Energy Holdings, Inc., owned an
approximate 19 percent membership interest in
U.S. Propane L.P. (USP), a joint venture formed in February
2000 with other utility companies to own a limited partnership
interest in Heritage Propane Partners, L.P. (Heritage), a
publicly-traded marketer of propane through a nationwide retail
distribution network. During fiscal 2004, we sold our interest
in USP and Heritage. As a result of these transactions, we no
longer have an interest in the propane business.
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Operating
Statistics
The following tables present certain operating statistics for
our utility, natural gas marketing, pipeline and storage and
other nonutility segments for each of the five fiscal years from
2002 through 2006.
Utility
Sales and Statistical Data
See footnotes following these tables.
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Utility
Sales and Statistical Data By Division
See footnotes following these tables.
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See footnotes following these tables.
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Notes to preceding tables:
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 jurisdictions operate in the best interests of
customers while providing utility companies the opportunity to
earn a reasonable return on investment. Generally, each
regulatory authority reviews our rate request and establishes a
rate structure intended to generate revenue sufficient to cover
our costs of doing business and provide a reasonable return on
invested capital.
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
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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 gross profit generated through
purchased gas adjustments because they 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, some 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
its customers.
The following table summarizes some information regarding our
ratemaking jurisdictions. This information is for regulatory
purposes only and may not be representative of our actual
financial position.
Jurisdictional
Rate Summary
See footnotes on the following page.
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Our current rate strategy focuses on seeking rate designs that
reduce or eliminate regulatory lag and separate the recovery of
our approved margins from customer usage patterns due to
weather-related variability, declining use per customer and
energy conservation, also known as decoupling. Additionally, we
are seeking to stratify rates for low income households and to
recover the gas cost portion of our bad debt expense.
Improving rate design is a long-term process. In the interim, we
are addressing regulatory lag issues by directing discretionary
capital spending to jurisdictions that permit us to recover our
investment in a timely manner and filing rate cases on a more
frequent basis to minimize the regulatory lag to keep our actual
returns more closely aligned with our allowed returns.
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Approximately 97 percent of our utility revenues in the
fiscal years ended September 30, 2006, 2005 and 2004 were
derived from sales at rates set by or subject to approval by
local or state authorities. Net annual revenue increases
resulting from ratemaking activity totaling $39.0 million,
$6.3 million and $16.2 million became effective in
fiscal 2006, 2005 and 2004 as summarized below:
Additionally, the following ratemaking efforts were initiated
during fiscal 2006 but had not been completed as of
September 30, 2006:
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Our recent ratemaking activity is discussed in greater detail
below.
Atmos Pipeline-Texas. In April 2006, Atmos
Pipeline — Texas made a filing under Texas’ Gas
Reliability Infrastructure Program (GRIP) to include in rate
base approximately $21.6 million of pipeline capital
expenditures incurred during calendar year 2005, which should
result in additional annual revenues of approximately
$3.3 million. The RRC approved this filing in July 2006 and
these new charges were included in the monthly customer charge
beginning in August 2006.
In September 2005, Atmos Pipeline — Texas made a GRIP
filing to include in rate base approximately $10.6 million
of pipeline capital expenditures incurred during calendar year
2004, which resulted in approximately $1.9 million in
additional annual revenue. In December 2004, Atmos
Pipeline — Texas made a GRIP filing to include in rate
base approximately $12.0 million of pipeline capital
expenditures made by TXU Gas during calendar year 2003, which
resulted in additional annual revenues of approximately
$1.8 million.
Atmos Energy Colorado-Kansas Division. In
December 2005, the Colorado-Kansas Division filed its second
annual ad valorem tax surcharge for $1.6 million. The
surcharge is designed to collect Kansas property taxes in excess
of the amount in the Colorado-Kansas Division’s most recent
general rate case. We began to bill this surcharge in January
2006.
In July 2004, the Colorado Public Utility Commission ordered us
to issue a one-time credit to our Colorado customers of
$1.9 million. The agreement was a result of an inquiry by
the Colorado Office of Consumer Counsel related to our earnings
in Colorado. The staff of the Colorado Public Utility Commission
was also a party to the agreement.
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. In January
2004, the Kansas Corporation Commission approved an agreement
that allowed a $2.5 million increase in our rates effective
March 2004. Additionally, the agreement allowed us to increase
our monthly customer charges from $5 to $8, provided that we
would not file another full rate application prior to September
2005. WNA became effective in Kansas in October 2003 in
accordance with the Kansas Corporation Commission’s ruling
in May 2003.
Atmos Energy Kentucky Division. In February
2006, the KPSC approved the Company’s request to continue
its Performance Based Ratemaking (PBR) mechanism for an
additional five year period. The PBR establishes predetermined
gas cost benchmarks and provides incentives to the Company for
purchasing gas supply below those benchmark costs.
In February 2005, the Attorney General of the State of Kentucky
filed a complaint with the Kentucky Public Service Commission
(KPSC) alleging that our rates were producing revenues in excess
of reasonable levels. We answered the complaint and filed a
Motion to Dismiss with the KPSC. In February 2006, the KPSC
issued an Order denying our Motion to Dismiss but stated that
the Attorney General had not met his burden of proof concerning
his complaint. In March 2006, the KPSC set a procedural schedule
for the case. The Attorney General is currently conducting
discovery. A hearing should be scheduled for early 2007. We
believe that the Attorney General will not be able to
demonstrate that our present rates are in excess of reasonable
levels.
Atmos Energy Louisiana Division. In September
2005, the Louisiana Public Service Commission (LPSC)
consolidated several then-existing dockets. These dockets
included a separate proceeding for the renewal of the Rate
Stabilization Clause (RSC) for each of the LGS and
TransLa Gas service areas; resolution of the outstanding
2003 RSC filing for the LGS service area; and our request for
approval of a decoupling mechanism to stabilize margins in both
the LGS and TransLa service areas.
On May 25, 2006, the LPSC voted to approve a settlement
which included a modified WNA providing for partial decoupling,
renewal of the RSC for both the LGS and TransLa service
areas with provisions that will reduce regulatory lag and a
refund to customers of approximately $0.4 million for the
LGS service areas that previously had been deferred. The first
RSC filing was in August 2006 for approximately
$10.8 million, based on a test year ended December 31,
2005, for the LGS service area. The increase is subject to
refund, pending final approval by the LPSC. The first filing for
the TransLa service area will be made by
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December 31, 2006, for the test period ending
September 30, 2006, with an effective rate adjustment of
April 1, 2007. WNA for both service areas will be in effect
for an initial three-year period beginning with the winter of
2006-2007.
In the third quarter of fiscal 2006, $6.2 million in
deferred revenue associated with the 2003 RSC rate adjustment
was recognized.
On August 29, 2005, Hurricane Katrina struck the Gulf
Coast, inflicting significant damage to our eastern Louisiana
operations. The hardest hit areas in our service territory were
in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes.
Although service has been restored for many of our customers, a
significant number of customers will not require gas service for
some time, if ever, because of sustained damages. We began
implementing new rates, subject to refund, in September 2006
that reflected the reduction of approximately 26,500 customers
and included a request to recover costs attributable to
Hurricane Katrina. We cannot accurately determine what
regulatory actions, if any, may be taken by the regulators with
respect to this filing or our ability to fully recover all costs
incurred as a result of the storm.
During the second quarter of 2005, the Louisiana Division
implemented a rate increase of $3.3 million in its LGS
service area. This increase resulted from our RSC filing in 2004
and was subject to refund, pending the final resolution of that
filing. As the rate increase was subject to refund, we did not
recognize the effects of this increase in our results of
operations during fiscal 2005 or the first three quarters of
fiscal 2006.
During fiscal 2004, the Louisiana Public Service Commission
approved tariff revisions for our LGS service area totaling
$0.2 million that became effective in October 2004.
In October 2002, Atmos received written notification from the
Executive Secretary of the LPSC 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 October 2003, the LPSC unanimously
voted to approve an agreement to allow us to charge a facilities
fee of approximately $0.5 million per month (subject to
future escalation) beginning November 2003 for a period of
14 years. No retroactive adjustments were required under
this agreement.
Atmos Energy Mid-States Division. In April
2006, Atmos filed a rate case in its Missouri service area
seeking a rate increase of $3.4 million. The Company is
proposing to consolidate the rates for its Missouri properties
into three sets of regional rates and consolidate the current
purchased gas adjustment (PGA) into one statewide PGA. The
Company is also proposing a WNA mechanism. An evidentiary
hearing is scheduled to begin on November 27, 2006, with an
order expected to be issued in February 2007.
In March 2006, we received notification from the Tennessee
Regulatory Authority (TRA) that it disagreed with the way we
calculated amounts under its performance-based rate mechanism,
which resulted in a one-time $3.3 million income reduction
during the second quarter of fiscal 2006. We believe the
original calculations were correct and have appealed the
TRA’s decision.
During the third quarter of fiscal 2005, Atmos filed a rate case
in its Georgia service area seeking a rate increase of
$4.0 million. In December 2005, the Georgia Public Service
Commission (GPSC) approved a $0.4 million increase. In
January 2006, we filed an appeal of the GPSC’s decision in
the Superior Court of Fulton County. Oral arguments were held on
September 7, 2006 before the Fulton County Superior Court.
The court affirmed the commission’s order. We are
considering further appeal.
In November 2005, we received a notice from the TRA that it was
opening an investigation into allegations by the Consumer
Advocate and Protection Division of the Tennessee Attorney
General’s Office that we were overcharging customers in
parts of Tennessee by approximately $10 million per year.
We responded to numerous data requests from the TRA Staff. In
April 2006, the TRA Staff filed a Report and Recommendation in
which it recommended that the TRA convene a contested case
procedure for the purpose of establishing a fair and reasonable
return. The TRA convened to consider the Staff’s
recommendation on May 15, 2006 and set a procedural
schedule. A hearing was held from August 29, 2006 through
August 31, 2006. Of the $10 million rate reduction
requested by the Consumer Advocate and Protection Division, the
TRA approved on October 27, 2006 a $6.1 million
reduction to future rates.
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In February 2004, the Mid-States Division filed a rate case with
the Virginia Corporation Commission (VCC) to request a
$1.0 million increase in our base rates, WNA and recovery
of the gas cost component of bad debt expense. The VCC granted a
rate increase in November 2004 of $0.4 million that was
retroactively effective to July 27, 2004. Additionally, the
VCC authorized WNA beginning in July 2005 and the ability to
recover the gas cost component of bad debt expense.
Atmos Energy Mid-Tex Division. The following
is a discussion of our recent ratemaking activity for our
Mid-Tex Division.
Rate
Case
During fiscal 2006, we received “show cause”
resolutions from approximately 80 cities served by our
Mid-Tex Division, including the City of Dallas, which require us
to demonstrate that existing distribution rates in the Mid-Tex
Division are just and reasonable. In May 2006, in response to
these resolutions, we filed a Statement of Intent to increase
rates on a division-wide basis. By agreement with the cities,
the “show cause” resolutions were consolidated and
became part of the Mid-Tex Division’s first rate case
before the RRC since we acquired the TXU Gas operations in
October 2004. In this rate proceeding, we are seeking
incremental annual revenues in the Mid-Tex Division of
approximately $60 million and several rate design changes,
including WNA, revenue stabilization and recovery of the gas
cost component of bad debt expense.
In exchange for an agreement to provide the intervening parties
in the proceeding additional time to prepare for the hearing, we
obtained agreement from the intervenors to implement WNA in the
rates for the Mid-Tex Division for the 2006-2007 winter season,
which has been approved by the RRC, and to implement WNA in the
final rates in this proceeding. The hearing in this proceeding
was concluded on November 17, 2006, and a decision is due
from the RRC no later than April 2007. During the hearing, the
principal issues raised by the cities included the Mid-Tex
Division’s rate of return, the reduction of rate base for
the accumulated deferred federal income taxes and investment tax
credits associated with the TXU Gas operations prior to our
acquisition, the methodology used by us to allocate certain
shared services expenses to the division, and the inclusion of
certain items in operation and maintenance expenses.
In addition, under applicable statutes, the RRC is reviewing the
interim rate adjustments that were previously granted in
response to the Mid-Tex Division’s prior GRIP filings and
our acquisition of the TXU Gas operations for consistency with
the public interest. Any increase that the RRC may grant in this
case would be effective prospectively from the date of the final
order. However, any decrease that may be ordered by the RRC
would be effective from May 31, 2006 pursuant to the
agreement with the intervenors for consolidation of the show
cause resolutions and the Statement of Intent filing. Any
disallowance related to the previously granted GRIP interim rate
adjustments would be refunded to customers with interest
beginning some time after the issuance of a final order in this
proceeding.
While the decision of the RRC in this case cannot be predicted
with certainty, we believe that we have adequately demonstrated
to the RRC that the Mid-Tex Division is entitled to receive an
increase in annual revenues and that the remaining rate design
changes should be implemented.
GRIP
Filings
In March 2006, the Mid-Tex Division made a GRIP filing to
include in rate base approximately $62.2 million of
distribution capital expenditures incurred during calendar year
2005, which we estimate would result in additional annual
revenues of approximately $11.9 million. The RRC approved
this filing in August 2006, and the new customer charges were
implemented in September 2006 billings to customers.
In September 2005, the Mid-Tex Division made a GRIP filing to
include in rate base approximately $29.4 million of
distribution capital expenditures incurred during calendar year
2004, which currently provides additional annual revenues of
approximately $6.7 million. The RRC approved this filing in
January 2006, and these new charges were included in the monthly
customer charge beginning in February 2006.
In December 2004, the Mid-Tex Division made a GRIP filing to
include in rate base approximately $32.0 million of
distribution capital expenditures made by TXU Gas during
calendar year 2003, which
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currently provides additional annual revenues of approximately
$6.7 million. New monthly customer charges were implemented
in October 2005.
Other
Regulatory Matters
In September 2006, the Mid-Tex Division filed its annual gas
cost reconciliation with the RRC. The filing reflects
approximately $24 million in refunds of amounts that were
overcollected from customers between July 2005 and June 2006.
The Mid-Tex Division has requested and received approval to
refund these amounts over a six-month period beginning in
November 2006.
In September 2004, the Mid-Tex Division filed its
36-Month Gas
Contract Review with the RRC. This proceeding involves a review
for reasonableness of gas purchases totaling $2.2 billion
made by the Mid-Tex Division from November 2000 through October
2003. A hearing on this matter was held before the RRC in June
2005. The parties negotiated a unanimous settlement agreement
providing for a refund of $8 million to customers over a
three-year period and for reimbursement of parties’
expenses without recovery from customers. The RRC approved the
settlement on September 12, 2006. Refunds to customers
began in the first quarter of fiscal year 2007.
The Mid-Tex Division is also pursuing an appeal to the Travis
County District Court of the Final Order in its last system-wide
rate case completed in May 2004 to obtain a return of and on its
investment associated with the Poly I replacement pipe that was
originally disallowed in its rate case completed in May 2004.
The case was argued before the Travis County District Court in
July 2006. The Court ruled to uphold the Commission’s final
order. Steps are being taken to perfect an appeal to the Court
of Appeals in Travis County.
Atmos Energy Mississippi Division. Through the
first quarter of fiscal 2005, the MPSC required that we file for
rate adjustments every six months. Rate filings were made in May
and November of each year and the rate adjustments typically
became effective in the following July and January.
During the second quarter of fiscal 2005, we agreed with the
MPSC to suspend our May 2005 semi-annual filing to allow
sufficient time for us and the MPSC to undertake a comprehensive
review in an effort to improve our rate design and the
ratemaking process. Effective October 2005, our rate design was
modified to substitute the original agreed-upon benchmark with a
sharing mechanism to allow the sharing of cost savings above an
allowed return on equity level. Further, we moved from a
semi-annual filing process to an annual filing process.
Additionally, our WNA period begins on November 1 instead
of November 15, and ends on April 30 instead of
May 15. Also, we now have a fixed monthly customer base
charge which makes a portion of our earnings less susceptible to
usage. As part of the rate design restructuring, we agreed to
reduce our rates by approximately $0.6 million. We made our
first annual filing under this new structure in September 2006
requesting no change in rates.
In September 2004, the MPSC originally disallowed certain
deferred costs totaling $2.8 million. In connection with
the modification of our rate design described above, the MPSC
decided to allow these costs, and we included these costs in our
rates in October 2005.
In June 2006, the MPSC approved a pilot program whereby Trans
Louisiana Gas Pipeline (TLGP) will provide asset management
services to the Mississippi Division. The asset management
program allows TLGP to market certain off-peak gas supply
assets, such as company-owned or leased storage and pipeline
capacity, on a recallable basis. In return, TLGP will share net
positive benefits of the asset management program with
Mississippi ratepayers. The pilot program runs from June 1,
2006 to April 30, 2007 and may be extended by the MPSC upon
application by Atmos.
In October 2003, the MPSC issued a final order that denied our
May 2003 request for a rate increase of $5.8 million. In
January 2004, the MPSC authorized additional annual revenue of
$5.9 million on our November 2003 filing, which became
effective in December 2003. In September 2004, the MPSC
authorized additional annualized revenue of $4.7 million on
our May 2004 filing, which became effective in June 2004.
We filed our second semiannual filing for 2004 in November 2004,
requesting rate adjustments of $6.0 million in annualized
revenue. The MPSC allowed us to include $3.0 million in
annualized revenue in
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our rates effective January 2005. In February 2005, we entered
into an agreement with the Mississippi Public Utilities Staff
that provides for an additional $1.3 million in annualized
revenue that was retroactive to January 2005, which was approved
by the MPSC during the second quarter of fiscal 2005.
Atmos Energy West Texas Division. In September
2005, the West Texas Division made a GRIP filing to include in
rate base approximately $22.6 million of distribution
capital costs incurred during calendar year 2004, which should
result in additional annual revenues of approximately
$3.8 million. Of this amount, approximately
$1.3 million related to our Lubbock jurisdiction and the
remaining $2.5 million related to our West Texas
jurisdiction. New charges for the filings were included in the
monthly customer charge beginning May 2006. Atmos made its 2005
GRIP filings for the West Texas Division and the Lubbock
Division in September 2006 requesting no change in rates.
In January 2006, the Lubbock, Texas City Council passed a
resolution requiring Atmos to submit copies of all documentation
necessary for the city to review the rates of Atmos’ West
Texas Division to ensure they are just and reasonable. The
requested information was provided to the city on
February 28, 2006. We believe that we will be able to
ultimately demonstrate to the City of Lubbock that our rates are
just and reasonable.
In May 2006, Atmos began receiving “show cause”
ordinances from several of the cities in the West Texas
Division. We made a filing in response to the ordinances on
October 2, 2006. We believe that we will be able to
ultimately demonstrate to the West Texas cities that our rates
are just and reasonable.
In October 2003, our West Texas Division filed a rate case in
Lubbock requesting a $3.0 million increase in annual
revenues and WNA for our residential, commercial and
public-authority customers. The City of Lubbock approved a
$1.5 million increase effective March 2004, as well as the
proposed WNA.
In September 2003, our West Texas Division filed a rate case in
its West Texas System to request a $7.7 million increase in
annual revenues and WNA for its residential, commercial and
public-authority customers. In May 2004, the 66 cities in
its West Texas System approved an increase of $3.2 million
in our annual utility revenues. The cities also approved a WNA
rider for residential, commercial, public-authority and
state-institution customers. This rider became effective in
October 2004.
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. Our
environmental claims have arisen primarily from former
manufactured gas plant sites in Tennessee, Iowa and Missouri.
These claims are fully described in Note 13 to the
consolidated financial statements.
FERC allows, pursuant to Section 311 of the Natural Gas
Policy Act, gas transportation services through our Atmos
Pipeline — Texas assets “on behalf of”
interstate pipelines or local distribution companies served by
interstate pipelines, without subjecting these assets to the
jurisdiction of the FERC.
Although 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,
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. Electric utilities offer electricity as a rival
energy source and compete for the space heating, water heating
and cooking markets. Promotional incentives, improved equipment
efficiencies and promotional rates all contribute to the
acceptability of electrical equipment. The principal means to
compete against alternative fuels is lower prices,
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and natural gas historically has maintained its price advantage
in the residential, commercial and industrial markets. However,
higher gas prices, coupled with the electric utilities’
marketing efforts, have increased competition for residential
and commercial customers. In addition, our Natural Gas Marketing
segment competes with other natural gas brokers in obtaining
natural gas supplies for our customers.
At September 30, 2006, we had 4,632 employees, consisting
of 4,402 employees in our utility segment and 230 employees in
our other segments. See “Operating Statistics —
Utility Sales and Statistical Data by Division” for the
number of employees by division.
Our Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and other reports, and amendments to those reports, that we file
with or furnish to the Securities and Exchange Commission (SEC)
are available free of charge at our website,
www.atmosenergy.com, as soon as reasonably practicable,
after we electronically file these reports with, or furnish
these reports to, the SEC. We will also provide copies of these
reports free of charge upon request to Shareholder Relations at
the address appearing below:
Shareholder Relations
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas
75265-0205
972-855-3729
In accordance with and pursuant to relevant provisions of the
Sarbanes-Oxley Act of 2002, related rules and regulations of the
Securities and Exchange Commission as well as corporate
governance-related listing standards of the New York Stock
Exchange, the Board of Directors of the Company has adopted the
Company’s Corporate Governance Guidelines and revised the
Company’s Code of Conduct, which is applicable to all
directors, officers and employees of the Company. In addition,
the Board of Directors has updated 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. We will
also provide copies of such information free of charge upon
request to Shareholder Relations at the address listed above.
Our financial and operating results are subject to a number of
factors, many of which are not within our control. Although we
have tried to discuss key risk factors below, please be aware
that other risks may prove to be important in the future. These
factors include the following:
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 and our
effectiveness in earning such rates and initiate rate
proceedings or operating changes as we believe are needed. In
addition, in the normal course of the regulatory environment,
assets may be placed in service and historical test periods
established before rate cases that could adjust our returns 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 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, rate cases
involve a risk of rate reduction, and once rates have been
approved, they are still subject to challenge for their
reasonableness by appropriate
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regulatory authorities. Our debt and equity financings are also
subject to approval by regulatory bodies in several states which
could limit our ability to take advantage of favorable 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. Although we
believe that our enhanced technology and distribution system
infrastructures have positively positioned us, we cannot provide
assurance that there would be no significant adverse effect on
our business should unbundling or further deregulation of the
natural gas distribution service business occur.
Our natural gas utility sales volumes and related revenues are
correlated with heating requirements that result from cold
winter weather. Although beginning in the 2006-2007 winter
heating season, we will have weather-normalized rates for over
90 percent of our residential and commercial meters that
should substantially eliminate the adverse effects of
warmer-than-normal weather for meters in those service areas,
our utility operating results will continue to vary with the
temperatures during the winter heating season. In addition,
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.
As a result of our acquisition of the distribution, pipeline and
storage operations of TXU Gas in October 2004, over 50 percent
of our natural gas distribution customers and most of our
pipeline and storage assets and operations are now located in
the State of Texas. This concentration of our business in Texas
means that our operations and financial results are subject to
greater impact than before from changes in the Texas economy in
general as well as the weather in our service areas of the state
during the winter heating season. Our financial results in
fiscal 2006 were adversely affected by warm weather in Texas. In
addition, the impact of any adverse rate or other regulatory
decisions by state or local regulatory authorities in Texas will
also be greater. The hearing in the Mid-Tex Division’s
first rate case since the TXU Gas acquisition has just
concluded. In the proceeding, we are seeking additional revenue
and several rate design changes. A rate reduction or other
significant, adverse decision by the Texas Railroad Commission
in the proceeding could materially affect our financial results.
We are subject to laws, regulations and other legal requirements
enacted or adopted by federal, state and local governmental
authorities relating to protection of the environment and health
and safety matters, including those legal requirements that
govern discharges of substances into the air and water, the
management and disposal of hazardous substances and waste, the
clean-up of
contaminated sites, groundwater quality and availability, plant
and wildlife protection, as well as work practices related to
employee health and safety. Environmental legislation also
requires that our facilities, sites and other properties
associated with our operations be operated, maintained,
abandoned and reclaimed to the satisfaction of applicable
regulatory authorities. Failure to comply with these laws,
regulations, permits and licenses may expose us to fines,
penalties or interruptions in our operations that could be
significant to our financial results. In addition, existing
environmental regulations may be revised or our operations may
become subject to new regulations. Such revised or new
regulations could result in increased compliance costs or
additional operating restrictions which could adversely affect
our business, financial condition and results of operations.
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Our risk management operations are subject to market risks
beyond our control including market liquidity, commodity price
volatility and counterparty creditworthiness.
Although we maintain a risk management policy, we may not be
able to completely offset the price risk associated with
volatile gas prices or the risk in our natural gas marketing and
pipeline and storage segments which could lead to volatility in
our earnings. Physical trading also introduces price risk on any
net open positions at the end of each trading day, as well as
volatility 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, there are times when
limited net open positions related to our physical storage may
occur on a short-term basis. The determination of our net open
position as of any day requires us to make assumptions as to
future circumstances, including the use of gas by our customers
in relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. Net open positions may increase
volatility in our financial condition or results of operations
if market prices move in a significantly favorable or
unfavorable manner because the timing of the recognition of
profits or losses on the hedges for financial accounting
purposes does not always match up with the timing of the
economic profits or losses on the item being hedged. This
volatility may occur with a resulting increase or decrease in
earnings or losses, even though the expected profit margin is
essentially unchanged from the date the transactions were
consummated. Further, if the local physical markets in which we
trade do not move consistently with the NYMEX futures market, we
could experience increased volatility in the financial results
of our natural gas marketing and pipeline and storage segments.
Our natural gas marketing and pipeline and storage segments
manage margins and limit 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. However, 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 could also realize financial losses on
our efforts to limit risk as a result of volatility in the
market prices of the underlying commodities or if a counterparty
fails to perform under a contract. In addition, adverse changes
in the creditworthiness of our counterparties could limit the
level of trading activities with these parties and increase the
risk that these parties may not perform under a contract.
We are also subject to interest rate risk on our commercial
paper borrowings and floating rate debt. In the past few years,
we have been operating in a relatively low interest-rate
environment with both short and long-term interest rates being
relatively low compared to past interest rates. However, in the
past two years, the Federal Reserve has taken actions that have
resulted in increases in short-term interest rates. Future
increases in interest rates could adversely affect our future
financial results.
We rely upon access to both short-term and long-term capital
markets to satisfy our liquidity requirements. Adverse changes
in the economy or these markets, the overall health of the
industries in which we operate and changes to our credit ratings
could limit access to these markets, increase our cost of
capital or restrict the execution of our business plan.
Our long-term debt is currently rated as “investment
grade” by Standard & Poor’s Corporation
(S&P), Moody’s Investors Services, Inc. (Moody’s)
and Fitch Ratings, Ltd. (Fitch), the three credit rating
agencies that rate our long-term debt securities. There can be
no assurance that these rating agencies will maintain investment
grade ratings for our long-term debt. If we were to lose our
investment-grade rating, the commercial paper markets and the
commodity derivatives markets could become unavailable to us.
This would increase our borrowing costs for working capital and
reduce the borrowing capacity of our gas marketing affiliate. In
addition, if our commercial paper ratings were lowered, it would
increase the cost of commercial
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paper financing and could reduce or eliminate our ability to
access the commercial paper markets. If we are unable to issue
commercial paper, we intend to borrow under our bank credit
facilities to meet our working capital needs. This would
increase the cost of our working capital financing.
Inflation has caused increases in some of our 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. However, the ability to control expenses is an important
factor that could influence future results.
Rapid increases in the price of purchased gas, which occurred
recently and in some prior years, cause 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 could result in higher short-term debt
levels, greater collection efforts and increased bad debt
expense.
In the residential and commercial customer markets, our
regulated utility operations compete with other energy products,
such as electricity and propane. Our primary product competition
is with electricity for heating, water heating and cooking.
Increases in the price of natural gas could negatively impact
our competitive position by decreasing the price benefits of
natural gas to the consumer. This could adversely impact our
business if as a result, our customer growth slows, resulting in
reduced ability to make capital expenditures, or if our
customers further conserve their use of gas, resulting in
reduced gas purchases and customer billings.
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 bypass
our systems in favor of special competitive contracts with lower
per-unit costs. Our pipeline and storage operations currently
face limited competition from other existing intrastate
pipelines and gas marketers seeking to provide or arrange
transportation, storage and other services for customers.
However, competition may increase if new intrastate pipelines
are constructed near our existing facilities.
We provide a cash-balance pension plan for the benefit of
eligible full-time employees as well as postretirement health
care benefits to eligible full-time employees. Our costs of
providing such benefits is subject to changes in the market
value of our pension fund assets, changing demographics,
including longer life expectancy of beneficiaries and an
expected increase in the number of eligible former employees
over the next five to ten years, and various actuarial
calculations and assumptions. The actuarial assumptions used may
differ materially from actual results due to changing market and
economic conditions, higher or lower withdrawal rates and other
factors. These differences may result in a significant impact on
the amount of pension expense or other postretirement benefit
costs recorded in future periods.
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We must continually build additional capacity in our natural gas
distribution system to maintain the growth in the number of our
customers. The cost of adding this capacity may be affected by a
number of factors, including the general state of the economy
and weather. Our cash flows from operations are generally not
sufficient to supply funding for all our capital expenditures
including the financing of the costs of this new construction
along with capital expenditures necessary to maintain our
existing natural gas system. As a result, we must fund at least
a portion of these costs through borrowing funds from third
party lenders, the cost of which is dependent on the interest
rates at the time. This in turn may limit our ability to connect
new customers to our system due to constraints on the amount of
funds we can invest in our infrastructure.
Our natural gas distribution business involves a number of
hazards and operating risks that cannot be completely avoided,
such as leaks, accidents and operational problems, which could
cause loss of human life, as well as substantial financial
losses resulting from property damage, damage to the environment
and to our operations. We do have liability and property
insurance coverage in place for many of these hazards and risks.
However, because our pipeline, storage and distribution
facilities are near or are in populated areas, any loss of human
life or adverse financial results resulting from such events
could be large. If these events were not fully covered by
insurance, our financial position and results of operations
could be adversely affected.
Natural disasters are always a threat to our assets and
operations. In addition, the threat of terrorist activities
could lead to increased economic instability and volatility in
the price of natural gas that could affect our operations. Also,
companies in our industry may face a heightened risk of exposure
to actual acts of terrorism, which could subject our operations
to increased risks. As a result, the availability of insurance
covering such risks may be more limited, which could increase
the risk that an event could adversely affect future financial
results.
Not applicable.
At September 30, 2006, our utility segment owned an
aggregate of 75,869 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. At
September 30, 2006, our pipeline and storage segment owned
6,127 miles of gas transmission and gathering lines.
Our utility segment also holds franchises granted by the
incorporated cities and towns that we serve. At
September 30, 2006, we held 1,103 franchises having terms
generally ranging from five to 35 years. A significant
number of our franchises expire each year, which require renewal
prior to the end of their terms. We believe that we will be able
to renew our franchises as they expire.
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Storage
Assets
Our utility and pipeline and storage 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 certain information regarding our underground
gas storage facilities:
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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:
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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.
Our administrative offices are consolidated in a leased facility
in Dallas, Texas. We also maintain field offices throughout our
distribution system, the majority of which are located in leased
facilities. Our nonutility 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 2006.
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The following table sets forth certain information as of
September 30, 2006, 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.
Kim R. Cocklin joined the Company in June 2006 as Senior Vice
President, Utility Operations to succeed R. Earl Fischer, who
retired from the Company on September 30, 2006. Prior to
joining the Company, Mr. Cocklin served as Senior Vice
President, General Counsel and Chief Compliance Officer of
Piedmont Natural Gas Company from February 2003 to May 2006.
Prior to joining Piedmont, Mr. Cocklin was with Williams
Gas Pipeline from 1995 to January 2003, where he served in
various capacities, including serving as Vice President for
rates, regulatory and business development for all of the
Williams Gas pipelines from 2001 to January 2003.
R. Earl Fischer was named Senior Vice President, Utility
Operations in May 2000. Mr. Fischer previously served the
Company as President of the Mid-Tex Division from October 2004
to October 2005. Mr. Fischer retired from the Company on
September 30, 2006.
Louis P. Gregory was named Senior Vice President and General
Counsel in September 2000.
Mark H. Johnson was named Senior Vice President, Nonutility
Operations in April 2006 and President of Atmos Energy Holdings,
Inc., and Atmos Energy Marketing, LLC, in April 2005.
Mr. Johnson previously served the Company as Vice
President, Nonutility Operations from October 2005 to March 2006
and as Executive Vice President of Atmos Energy Marketing from
October 2003 to March 2005. Mr. Johnson joined Atmos Energy
Marketing’s predecessor, Woodward Marketing, L.L.C., in
1992 as Vice President of Marketing and Operations and was later
promoted to Senior Vice President of Marketing for the Midwest
and Gulf Coast. Mr. Johnson succeeded JD Woodward III
who retired from the Company effective April 1, 2006.
Wynn D. McGregor was named Senior Vice President, Human
Resources in October 2005. He previously served the Company as
Vice President, Human Resources from January 1994 to September
2005.
John P. Reddy was named Senior Vice President and Chief
Financial Officer in September 2000.
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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 2006 and
2005 are listed below. The high and low prices listed are the
closing NYSE quotes for shares of our common stock:
Dividends are payable at the discretion of our Board of
Directors out of legally available funds and are also subject to
restriction under the terms of our First Mortgage Bond
agreement. See Note 6 to the consolidated financial
statements. The Board of Directors typically declares dividends
in the same fiscal quarter in which they are paid. The number of
record holders of our common stock on October 31, 2006 was
24,425. Future payments of dividends, and the amounts of these
dividends, will depend on our financial condition, results of
operations, capital requirements and other factors. We sold no
securities during fiscal 2006 that were not registered under the
Securities Act of 1933, as amended.
The following table sets forth the number of securities
authorized for issuance under our equity compensation plans at
September 30, 2006.
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The following table sets forth selected financial data of the
Company and should be read in conjunction with the consolidated
financial statements included herein.
See footnotes on the following page.
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The following table presents a condensed income statement by
segment for the year ended September 30, 2006.
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This section provides management’s discussion of the
financial condition, changes in financial condition and results
of operations of Atmos Energy Corporation and its consolidated
subsidiaries 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 our consolidated financial statements and notes thereto.
Our performance in the future will primarily depend on the
results of our utility and nonutility operations. Several
factors exist that could influence our future financial
performance, some of which are described in Item 1A above,
“Risk Factors”. 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 set out in such forward-looking
statements.
The statements contained in this Annual Report on
Form 10-K
may contain “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933 and
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
us 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
our documents or oral presentations, the words
“anticipate”, “believe”,
“estimate”, “expect”, “forecast”,
“goal”, “intend”, “objective”,
“plan”, “projection”, “seek”,
“strategy” 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 our strategy, operations, markets,
services, rates, recovery of costs, availability of gas supply
and other factors. These risks and uncertainties include the
following: regulatory trends and decisions, including
deregulation initiatives and the impact of rate proceedings
before various state regulatory commissions; adverse weather
conditions, such as warmer than normal weather in our utility
service territories or colder than normal weather that could
adversely affect our natural gas marketing activities; the
concentration of our distribution, pipeline and storage
operations in one state; impact of environmental regulations on
our business; market risks beyond our control affecting our risk
management activities including market liquidity, commodity
price volatility, increasing interest rates and counterparty
creditworthiness; our ability to continue to access the capital
markets; the effects of inflation and changes in the
availability and prices of natural gas, including the volatility
of natural gas prices; increased competition from energy
suppliers and alternative forms of energy; increased costs of
providing pension and postretirement health care benefits; the
capital-intensive nature of our distribution business, the
inherent hazards and risks involved in operating our
distribution business, and other risks and uncertainties
discussed herein, especially in Item 1A above, all of which
are difficult to predict and many of which are beyond our
control. Accordingly, while we believe 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, we undertake no
obligation to update or revise any of our forward-looking
statements whether as a result of new information, future events
or otherwise.
In fiscal 2006, we earned $147.7 million in net income or
$1.82 per diluted share, compared with net income of
$135.8 million, or $1.72 per diluted share in fiscal
2005. The nine percent
year-over-year
increase in net income was primarily attributable strong
financial results in our natural gas marketing segment as it was
able to capture higher margins in a volatile natural gas market
and favorable unrealized
mark-to-market
gains. Additionally, pipeline and storage net income increased
16 percent compared with the prior year. These positive
results helped overcome the adverse effects on our utility
segment of weather (adjusted for WNA) that
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was 13 percent warmer than normal, the adverse effect of
Hurricane Katrina on our Louisiana Division and a non-recurring,
noncash charge to impair certain assets. Our utility operations
contributed $53.0 million ($0.65 per diluted share) or
36 percent to fiscal 2006 results. Our nonutility
operations, comprised of our natural gas marketing, pipeline and
storage and other nonutility segments, contributed
$94.7 million ($1.17 per diluted share) or
64 percent to fiscal 2006 results. Key financial and other
events for fiscal 2006 include the following:
Our financial performance is discussed in greater detail below
in Results of Operations.
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 quarterly. Actual results may
differ from estimates.
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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 costs that would
normally be expensed under accounting principles generally
accepted in the United States are permitted to be capitalized
because they can be recovered through rates. Further, regulation
may impact the period in which revenues or expenses are
recognized. The amounts to be recovered or recognized are based
upon historical experience and our understanding of the
regulations. The impact of regulation on our utility operations
may be affected by decisions of the regulatory authorities or
the issuance of new regulations.
Revenue recognition — Sales of natural gas to
our utility customers are billed on a monthly cycle basis;
however, the billing cycle periods for certain classes of
customers do not necessarily coincide with accounting periods
used for financial reporting purposes. We follow the revenue
accrual method of accounting for utility segment revenues
whereby revenues applicable to gas delivered to customers, but
not yet billed under the cycle billing method, are estimated and
accrued and the related costs are charged to expense.
On occasion, we are permitted to implement new rates that have
not been formally approved by our regulators and are subject to
refund. As permitted by SFAS No. 71, we recognize this
revenue and establish a reserve for amounts that could be
refunded based on our experience for the jurisdiction in which
the rates were implemented.
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 gross profit 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 is generally not affected by fluctuations in the cost of
gas due to the purchased gas adjustment mechanism. The effects
of these purchased gas adjustment mechanisms are recorded as
deferred gas costs on our balance sheet.
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 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. Accounts are written off
once they are deemed to be uncollectible.
Derivatives and hedging activities — In our
utility segment, we use a combination of storage and financial
derivatives to partially insulate us and our natural gas utility
customers against gas price volatility
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during the winter heating season. The financial derivatives we
use in our utility segment 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 these derivatives primarily result from changes in the
valuation of the portfolio of contracts, the maturity and
settlement of contracts and newly originated transactions.
However, because the costs of financial derivatives 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 derivatives. 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.
Our natural gas marketing risk management activities are
conducted through our natural gas marketing segment. This
segment is exposed to risks associated with changes in the
market price of natural gas, which we manage through a
combination of storage and financial derivatives, including
futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. Option contracts provide the right, but not the
requirement, to buy or sell the commodity at a fixed price. Swap
contracts require receipt of payment for the commodity based on
the difference between a fixed price and the market price on the
settlement date. The use of these contracts is subject to our
risk management policies, which are monitored for compliance
daily.
We participate in transactions in which we combine the natural
gas commodity and transportation costs to minimize our costs
incurred to serve our customers. Additionally, we engage in
natural gas storage transactions in which we seek to find and
profit from pricing differences that occur over time. We
purchase or sell physical natural gas and then sell or purchase
financial contracts at a price sufficient to cover our carrying
costs and provide a gross profit margin. Through the use of
transportation and storage services and derivatives, we seek to
capture gross profit margin through the arbitrage of pricing
differences in various locations and by recognizing pricing
differences that occur over time.
Under SFAS 133, natural gas inventory is designated as the
hedged item in a fair-value hedge by AEM and Atmos Pipeline and
Storage LLC. This inventory is marked to market at the end of
each month with changes in fair value recognized as unrealized
gains or losses in revenue in the period of change. Effective
October 2005, we changed the index used to value our physical
natural gas from Inside FERC to Gas Daily to better reflect the
prices of our physical commodity. This change had no material
impact on our financial position on the date of adoption. Costs
to store the gas are recognized in the period the costs are
incurred. We recognize revenue and the carrying value of the
inventory as an associated purchased gas cost in our
consolidated statement of income when we sell the gas and
deliver it out of the storage facility.
Derivatives associated with our natural gas inventory are marked
to market each month based upon the NYMEX price with changes in
fair value recognized as unrealized gains or losses in the
period of change. The difference in the indices used to mark to
market our physical inventory (Gas Daily) and the related
fair-value hedges (NYMEX) are reported as a component of revenue
and can result in volatility in our reported net income. Over
time, we expect gains and losses on the sale of storage gas
inventory to be offset by gains and losses on the fair-value
hedges, resulting in the realization of the economic gross
profit margin we anticipated at the time we structured the
original transaction. We continually manage our positions and
seek to optimize value as market conditions and other
circumstances change. We elect to exclude the differential
between the spot price used to value our physical inventory and
the forward price used to value the financial hedges designated
against our physical inventory for purposes of assessing the
effectiveness of these fair-value hedges.
Similar to our inventory position, we attempt to mitigate
substantially all of the commodity price risk associated with
our fixed-price contracts with minimum volume requirements
through the use of various offsetting derivatives. Prior to
April 2004, these derivatives were not designated as hedges
under SFAS 133 because they naturally locked in the
economic gross profit margin at the time we entered into the
contract. The fixed-price forward and offsetting derivative
contracts were marked to market each month with changes in fair
value recognized as unrealized gains and losses recorded in
revenue in our consolidated statement of income. The unrealized
gains and losses were realized as a component of revenue in the
period in which we fulfilled the requirements of the fixed-price
contract and the derivatives settled. To the extent that the
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unrealized gains and losses of the fixed-price forward contracts
and the offsetting derivatives did not offset exactly, our
earnings experienced some volatility. At delivery, the gains and
losses on the fixed-price contracts were offset by gains and
losses on the derivatives, resulting in the realization of the
economic gross profit margin we anticipated at the time we
structured the original transaction.
Effective April 2004, we elected to treat our fixed-price
forward contracts as normal purchases and sales. As a result, we
ceased marking the fixed-price forward contracts to market. We
designated the offsetting derivative contracts as cash flow
hedges of anticipated transactions. As a result of this change,
unrealized gains and losses on these open derivative contracts
have been recorded as a component of accumulated other
comprehensive income and are recognized in earnings as a
component of revenue when the hedged volumes are sold. Hedge
ineffectiveness, to the extent incurred, is reported as a
component of revenue.
Additionally, we utilize storage swaps and futures to capture
additional storage arbitrage opportunities that arise subsequent
to the execution of the original fair value hedge associated
with our physical natural gas inventory, basis swaps to insulate
and protect the economic value of our fixed price and storage
books and various over-the-counter and exchange-traded options.
Although the purpose of these instruments is to either reduce
basis or other risks or lock in arbitrage opportunities, these
derivative instruments have not been designated as hedges.
Accordingly, these derivative instruments are recorded at fair
value with all changes in fair value included in revenue in our
natural gas marketing segment.
During fiscal 2004, we entered into four Treasury lock
agreements to fix the Treasury yield component of the interest
cost of financing associated with the anticipated issuance of
$875 million of long-term debt. We designated these
Treasury lock agreements as cash flow hedges of an anticipated
transaction. Accordingly, unrealized gains and losses associated
with the Treasury lock agreements were recorded as a component
of accumulated other comprehensive income. These Treasury lock
agreements were settled in October 2004 with a net
$43.8 million payment to the counterparties. This realized
loss is being recognized as a component of interest expense over
the life of the related financing arrangements.
The fair value of our financial derivatives is determined
through a combination of prices actively quoted on national
exchanges, prices provided by other external sources and prices
based on models and other valuation methods. Changes in the
valuation of our financial derivatives primarily result from
changes in market prices, the valuation of the portfolio of our
contracts, maturity and settlement of these contracts and newly
originated transactions, each of which directly affect the
estimated fair value of our derivatives. We believe the market
prices and models used to value these derivatives represent the
best information available with respect to 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 then current market conditions.
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. We have determined our
reporting units to be each of our utility divisions and
wholly-owned subsidiaries. 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
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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 costs and liabilities are
determined on an actuarial basis and are affected by numerous
assumptions and estimates including the market value of plan
assets, estimates of the expected return on plan assets, assumed
discount rates and current demographic and actuarial mortality
data. We review the estimates and assumptions underlying our
pension and other postretirement plan costs and liabilities
annually based upon a June 30 measurement date. The assumed
discount rate and the expected return are the assumptions that
generally have the most significant impact on our pension costs
and liabilities. The assumed discount rate, the assumed health
care cost trend rate and assumed rates of retirement generally
have the most significant impact on our postretirement plan
costs and liabilities.
The discount rate is utilized principally in calculating the
actuarial present value of our pension and postretirement
obligation and net pension and postretirement cost. When
establishing our discount rate, we consider high quality
corporate bond rates based on Moody’s Aa bond index,
changes in those rates from the prior year and the implied
discount rate that is derived from matching our projected
benefit disbursements with a high quality corporate bond spot
rate curve.
The expected long-term rate of return on assets is utilized in
calculating the expected return on plan assets component of our
annual pension and postretirement plan cost. We estimate the
expected return on plan assets by evaluating expected bond
returns, equity risk premiums, asset allocations, the effects of
active plan management, the impact of periodic plan asset
rebalancing and historical performance. We also consider the
guidance from our investment advisors in making a final
determination of our expected rate of return on assets. To the
extent the actual rate of return on assets realized over the
course of a year is greater than or less than the assumed rate,
that year’s annual pension or postretirement plan cost is
not affected. Rather, this gain or loss reduces or increases
future pension or postretirement plan cost over a period of
approximately ten to twelve years.
We estimate the assumed health care cost trend rate used in
determining our postretirement net expense based upon our actual
health care cost experience, the effects of recently enacted
legislation and general economic conditions. Our assumed rate of
retirement is estimated based upon our annual review of our
participant census information as of the measurement date.
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 cost ultimately recognized. A
0.25 percent change in our discount rate would impact our
pension and postretirement cost by approximately
$1.1 million. A 0.25 percent change in our expected
rate of return would impact our pension and postretirement cost
by approximately $0.8 million.
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RESULTS
OF OPERATIONS
The following table presents our financial highlights for the
three fiscal years ended September 30, 2006:
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The following table shows our operating income by utility
division and by segment for the three fiscal years ended
September 30, 2006. The presentation of our utility
operating income is included for financial reporting purposes
and may not be appropriate for ratemaking purposes.
Year
ended September 30, 2006 compared with year ended
September 30, 2005
Our utility segment has historically contributed 65 to
85 percent of our consolidated net income. However, during
fiscal 2006, our utility segment contributed approximately
36 percent of our consolidated net income primarily due to
the adverse effect of significantly warmer than normal weather,
the adverse effect of Hurricane Katrina and a non-recurring,
noncash charge to recognize the impairment of our irrigation
assets. The primary factors that impact the results of our
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
has historically been our most critical earnings quarter with an
average of approximately 64 percent of our consolidated net
income having been earned in the second quarter during the three
most recently completed fiscal years. Additionally, we typically
experience higher levels of accounts receivable, accounts
payable, gas stored underground and short-term debt balances
during the winter heating season due to the seasonal nature of
our revenues and the need to purchase and store gas to support
these operations. Utility sales to industrial customers are much
less weather sensitive.
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 our customers.
Accordingly, we believe gross profit margin is a better
indicator of our financial performance than revenues. However,
higher gas costs may cause customers to conserve or, in the case
of industrial customers, to use alternative energy sources.
Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt
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expense, and may require us to increase borrowings under our
credit facilities resulting in higher interest expense.
The effects of weather that is above or below normal are
substantially offset through weather normalization adjustments
in most of our 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. Accordingly, in our WNA service areas, our gross
profit margin should be based substantially on the amount of
gross profit that would result from normal weather, despite
actual weather conditions that may be either warmer or colder
than normal.
During fiscal 2006, we received WNA in our two most weather
sensitive jurisdictions: the Louisiana and Mid-Tex divisions.
With the addition of WNA in these two jurisdictions, we will
have weather protection for over 90 percent of our
residential and commercial meters for the 2006-2007 winter
heating season. Prior to these decisions, there was limited
weather protection in these jurisdictions. The Louisiana
Division had previously benefited from a higher base customer
charge. However, this rate structure was not as beneficial
during periods where weather was significantly warmer than
normal. In May 2006, the LPSC approved a settlement that
provided for a modified WNA which provides a partial decoupling
mechanism to stabilize this jurisdiction’s margins. The
approved WNA will cover a period from December to March.
Prior to October 1, 2006, the
Mid-Tex
Division, which is our largest utility division and contains
almost 50 percent of our approximately 3.2 million
distribution customers, had benefited from a rate structure that
combined a monthly customer charge with a declining block rate
schedule to partially mitigate the impact of warmer-than-normal
weather on revenue. The combination of the monthly customer
charge and the customer billing under the first block of the
declining block rate schedule provided for the recovery of a
significant portion of our fixed costs for such operations under
average weather conditions. However, this rate structure was not
as beneficial during periods where weather was significantly
warmer than normal.
In July 2006, in connection with the
Mid-Tex
Division rate proceeding the RRC approved an interim and a
permanent WNA effective October 1, 2006 for the
Mid-Tex
Division. The WNA covers the period from October through May.
The interim WNA is based on 30 years of weather history,
and the permanent WNA will be modified or adjusted to conform to
the rate design that the RRC ultimately approves in the rate
proceeding, which proceeding is described in greater detail
under Recent Ratemaking Activity.
In the pending rate proceeding before the RRC, we are seeking
for our
Mid-Tex
Division additional annual revenues of approximately
$60 million and several rate design changes including
revenue stabilization and recovery of the gas cost component of
bad debt expense. While the outcome of the
Mid-Tex
Division’s pending rate proceeding before the RRC cannot be
predicted with certainty, we believe that we have adequately
demonstrated to the RRC that the
Mid-Tex
Division is entitled to receive an increase in annual revenues
and that the remaining rate design changes should be
implemented. However, if the RRC were to deny an increase in the
Mid-Tex
Division’s rates or not allow new rate design changes the
Mid-Tex
Division has requested, our business, financial condition and
results of operations could be adversely affected in the future.
Utility gross profit increased to $925.1 million for the
year ended September 30, 2006 from $907.4 million for
the year ended September 30, 2005. Total throughput for our
utility business was 394.0 Bcf during the current year
compared to 411.1 Bcf in the prior year.
The increase in utility gross profit, despite lower throughput,
primarily reflects higher franchise fees and state gross
receipts taxes, which are paid by utility customers and have no
permanent effect on net income. Additionally, margins increased
approximately $14.0 million due to rate increases received
from our fiscal 2005 and fiscal 2004 GRIP filings and the
recognition of $6.2 million that had been previously
deferred in Louisiana following the LPSC’s ratification of
our agreement in May 2006. These increases were partially offset
by approximately $22.9 million due to the impact of
significantly warmer than normal weather, particularly in our
Mid-Tex and Louisiana divisions. For the year ended
September 30, 2006, weather was
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13 percent warmer than normal, as adjusted for
jurisdictions with weather-normalized operations and two percent
warmer than the prior year. In the Mid-Tex and Louisiana
Divisions, which did not have weather-normalized rates during
the
2005-2006
winter heating season, weather was 28 percent and
22 percent warmer than normal.
Additionally, utility gross profit decreased approximately
$2.9 million compared with the prior year in the Louisiana
Division due to the impact of Hurricane Katrina. Service has
been restored in some areas affected by the storm; however, it
is not likely that service will be restored to all of the
affected service areas. As more fully described under Recent
Ratemaking Activity, we implemented new rates in September 2006
that reflect the impact of Hurricane Katrina.
Operating expenses increased to $723.2 million for the year
ended September 30, 2006 from $671.0 million for the
year ended September 30, 2005. The increase reflects a
$13.3 million increase in taxes, primarily related to
franchise fees and state gross receipts taxes, both of which are
calculated as a percentage of revenue, and are paid by our
customers as a component of their monthly bills. Although these
amounts are included as a component of revenue in accordance
with our tariffs, timing differences between when these amounts
are billed to our customers and when we recognize the associated
expense may affect net income favorably or unfavorably on a
temporary basis. However, there is no permanent effect on net
income.
Operation and maintenance expense, excluding the provision for
doubtful accounts, increased $7.8 million primarily due to
higher employee costs associated with increased headcount to
fill positions that were previously outsourced to a third party,
higher medical and dental claims and increased pension and
postretirement costs resulting from changes in the assumptions
used to determine our fiscal 2006 costs. Increased line locate,
telecommunication and facilities costs also contributed to the
overall increase. These increases were partially offset by a
reduction in third-party costs for outsourced administrative and
meter reading functions that were in-sourced during fiscal 2006.
Operation and maintenance expense for the year ended
September 30, 2006 was also favorably impacted by the
absence of $2.1 million of merger and integration cost
amortization associated with the merger of United Cities Gas
Company in July 1997, as these costs were fully amortized by
December 2004.
The provision for doubtful accounts increased $3.1 million
to $20.6 million for the year ended September 30,
2006, compared with $17.5 million in the prior year. The
increase was primarily attributable to increased collection risk
associated with higher natural gas prices. In the utility
segment, the average cost of natural gas for the year ended
September 30, 2006 was $10.02 per Mcf, compared with
$7.41 per Mcf for the year ended September 30, 2005.
Additionally, during the first quarter of fiscal 2006, the MPSC,
in connection with the modification of our rate design described
in Recent Ratemaking Activity, decided to allow the recovery of
$2.8 million in deferred costs, which it had originally
disallowed in its September 2004 decision. This charge was
originally recorded in fiscal 2004. This ruling decreased our
depreciation expense during the year ended September 30,
2006. This decrease was offset by increased depreciation expense
associated with the placement of various capital projects into
service during the fiscal year.
Operating expenses were also impacted by $22.9 million
noncash charge to impair our West Texas Division’s
irrigation assets. During the fiscal 2006 fourth quarter, we
determined that, as a result of declining irrigation sales
primarily associated with our agricultural customers’ shift
from gas-powered pumps to electric pumps, the West Texas
Division’s irrigation assets would not be able to generate
sufficient future cash flows from operations to recover the net
investment in these assets. Therefore, the entire net book value
was written off. We will continue to operate these assets until
we determine a plan for these assets as we are obligated to
provide natural gas services to certain customers served by
these assets.
As a result of the aforementioned factors, our utility segment
operating income for the year ended September 30, 2006
decreased to $201.9 million from $236.4 million for
the year ended September 30, 2005.
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Miscellaneous income for the year ended September 30, 2006
was $9.5 million compared to miscellaneous income of
$6.8 million for the year ended September 30, 2005.
This increase was primarily attributable to increased interest
income on intercompany borrowings to our natural gas marketing
segment to fund its working capital needs. This increase was
partially offset by a $3.3 million charge recorded during
the fiscal 2006 second quarter associated with an adverse ruling
in Tennessee related to the calculation of a performance-based
rate mechanism associated with gas purchases.
Interest charges allocated to the utility segment for the year
ended September 30, 2006 increased to $126.5 million
from $112.4 million for the year ended September 30,
2005. The increase was attributable to higher average
outstanding short-term debt balances to fund natural gas
purchases at significantly higher prices coupled with an
approximate 200 basis point increase in the interest rate
on our $300 million unsecured floating rate Senior Notes
due 2007 due to an increase in the three-month LIBOR rate. These
increases were partially offset by $4.8 million of interest
savings arising from the early payoff of $72.5 million of
our First Mortgage Bonds in June 2005.
Our natural gas marketing segment aggregates and purchases gas
supply, arranges transportation
and/or
storage logistics and ultimately delivers gas to our customers
at competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request, including
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. As a result, our revenues arise
from the types of commercial transactions we have structured
with our customers and include the value we extract by
optimizing the storage and transportation capacity we own or
control as well as revenues for services we deliver.
To optimize the storage and transportation capacity we own or
control, we participate in transactions in which we combine the
natural gas commodity and transportation costs to minimize our
costs incurred to serve our customers by identifying the lowest
cost alternative within the natural gas supplies, transportation
and markets to which we have access. Additionally, we engage in
natural gas storage transactions in which we seek to find and
profit from the pricing differences that occur over time. We
purchase physical natural gas and then sell financial contracts
at favorable prices to lock in gross profit margins. Through the
use of transportation and storage services and derivative
contracts, we seek to capture gross profit margin through the
arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
Gross profit margin for our natural gas marketing segment
consists primarily of marketing activities, which represent the
utilization of proprietary and customer-owned transportation and
storage assets to provide the various services our customers
request, and storage activities, which are derived from the
optimization of our managed proprietary and third party storage
and transportation assets.
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Our natural gas marketing segment’s gross profit margin was
comprised of the following for the year ended September 30,
2006 and 2005:
Our natural gas marketing segment’s gross profit margin was
$130.6 million for the year ended September 30, 2006
compared to gross profit of $62.0 million for the year
ended September 30, 2005. Gross profit margin from our
natural gas marketing segment for the year ended
September 30, 2006 included an unrealized gain of
$17.2 million compared with an unrealized loss of
$26.0 million in the prior year. Natural gas marketing
sales volumes were 336.5 Bcf during the year ended
September 30, 2006 compared with 273.2 Bcf for the
prior year. Excluding intersegment sales volumes, natural gas
marketing sales volumes were 284.0 Bcf during the current
year compared with 238.1 Bcf in the prior year. The
increase in consolidated natural gas marketing sales volumes was
primarily due to focusing our marketing efforts on higher margin
opportunities partially offset by
warmer-than-normal
weather across our market areas.
Our storage activities generated $24.9 million in gross
profit margin for the year ended September 30, 2006
compared to $14.0 million for the year ended
September 30, 2005. Lower realized margins in our storage
operations were primarily due to the realization of less
favorable arbitrage spreads compared with the prior year coupled
with increased storage fees. These decreases were partially
offset by a decrease in the unrealized loss associated with
these operations due to a favorable movement during the year
ended September 30, 2006 in the forward natural gas prices
used to value the financial hedges designated against our
physical inventory and our fixed-price forward contracts. These
decreases were also favorably impacted by positive basis
ineffectiveness resulting from natural gas market price
differences between the locations of the hedged inventory and
the delivery location specified in the derivative instruments
designated as a fair value hedge. These results were magnified
by a 7.6 Bcf increase in our net physical position at
September 30, 2006 compared to the prior year. We
continually seek opportunities to increase the amount of our
storage capacity. To the extent we obtain and utilize new
capacity and experience price volatility, the amount of our
unrealized storage contribution could increase in future periods.
Our marketing activities generated $105.7 million in gross
profit margin for the year ended September 30, 2006
compared with $48.0 million for the year ended
September 30, 2005. This increase reflects increased
realized margins coupled with a favorable unrealized margin
variance compared with the prior year. The increase in our
realized marketing operations was primarily attributable to
successfully capturing increased margins in certain market areas
that experienced higher market volatility. The favorable
unrealized margin variance was primarily due to favorable
movement during the year ended September 30, 2006 in the
forward natural gas prices associated with financial derivatives
used in these activities and positive basis ineffectiveness on
those financial derivatives.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $28.4 million for the
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year ended September 30, 2006 from $21.0 million for
the year ended September 30, 2005. The increase in
operating expense primarily was attributable to an increase in
personnel costs due to increased headcount and an increase in
regulatory compliance costs.
The improved gross profit margin partially offset by higher
operating expenses resulted in an increase in our natural gas
marketing segment operating income to $102.2 million for
the year ended September 30, 2006 compared with operating
income of $41.0 million for the year ended
September 30, 2005.
Interest charges allocated to the natural gas marketing segment
for the year ended September 30, 2006 increased to
$8.5 million from $3.4 million for the year ended
September 30, 2005. The increase was attributable to higher
average outstanding debt balances to fund natural gas purchases
at significantly higher prices.
Our pipeline and storage segment consists of the regulated
pipeline and storage operations of the Atmos
Pipeline — Texas Division and the nonregulated
pipeline and storage operations of Atmos Pipeline and Storage,
LLC (APS), which were previously included in our other
nonutility segment. The Atmos Pipeline — Texas
Division transports natural gas to our Mid-Tex Division and for
third parties and manages five underground storage reservoirs in
Texas. We also provide ancillary services customary in the
pipeline industry including parking arrangements, lending and
sales of inventory on hand. These operations represent one of
the largest intrastate pipeline operations in Texas with a heavy
concentration in the established natural gas-producing areas of
central, northern and eastern Texas, extending into or near the
major producing areas of the Texas Gulf Coast and the Delaware
and Val Verde Basins of West Texas. This pipeline system
provides access to nine basins located in Texas, which are
estimated to contain a substantial portion of the nation’s
remaining onshore natural gas reserves. APS owns or has an
interest in underground storage fields in Kentucky and
Louisiana. We also use these storage facilities to reduce the
need to contract for additional pipeline capacity to meet
customer demand during peak periods.
Similar to our utility segment, our pipeline and storage segment
is impacted by seasonal weather patterns, competitive factors in
the energy industry and economic conditions in our service
areas. Natural gas transportation requirements are affected by
the winter heating season requirements of our customers. 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. Further, as the Atmos Pipeline — Texas Division
operations supply all of the natural gas for our Mid-Tex
Division, the results of this segment are highly dependent upon
the natural gas requirements of the Mid-Tex Division. As a
regulated pipeline, the operations of the Atmos
Pipeline — Texas Division may be impacted by the
timing of when costs and expenses are incurred and when these
costs and expenses are recovered through its tariffs.
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Gross profit margin for our pipeline and storage segment
primarily consists of transportation margins earned from our
Mid-Tex Division and from third parties, other ancillary
pipeline services and asset management fees earned by APS. Our
pipeline and storage segment’s gross profit margin was
comprised of the following components for the year ended
September 30, 2006 and 2005:
Pipeline and storage gross profit increased to
$159.7 million for the year ended September 30, 2006
from $146.5 million for the year ended September 30,
2005. Total pipeline transportation volumes were 591.0 Bcf
during the year ended September 30, 2006 compared with
563.9 Bcf for the prior year. Excluding intersegment
transportation volumes, total pipeline transportation volumes
were 420.2 Bcf during the current year compared with
383.4 Bcf in the prior year.
The increase in gross profit was primarily attributable to
increased third-party throughput and ancillary services, coupled
with increased margins on APS’ asset management contracts.
Increased third-party throughput on Atmos Pipeline —
Texas was primarily attributable to increases in the
electric-generation market due to the warmer than normal
temperatures during the summer of 2006, increased demand for
through-system transportation services due to a widening of
pricing differentials between the pipeline’s hubs and the
impact of Atmos Pipeline — Texas’ North Side Loop
and other compression projects that were placed into service in
June 2006. Storage and parking and lending services on Atmos
Pipeline — Texas also increased during fiscal 2006 as
a result of the widening of pricing differentials between the
pipeline’s hubs, which increased the attractiveness of
storing gas on the pipeline and our ability to obtain improved
margins for these services. The increases on Atmos
Pipeline — Texas’ system were partially offset by
a decrease in margins earned from intercompany transportation
services to our Mid-Tex Division due to the significantly warmer
than normal weather experienced during fiscal 2006.
Additionally, these increases were partially offset by the
absence of inventory sales of $3.0 million realized in the
prior year.
Increases in APS’ margins due to its ability to capture
more favorable arbitrage spreads on its asset management
contracts also contributed to this segment’s improved gross
profit margin. These improved margins reflect an unrealized
component as APS hedges its risk associated with these
contracts. During fiscal 2006, favorable movements in the
forward natural gas prices used to value the financial hedges
designated against the physical inventory underlying these
contracts resulted in an unrealized gain compared with an
unrealized loss in the prior year.
Operating expenses increased to $81.9 million for the year
ended September 30, 2006 from $76.2 million for the
year ended September 30, 2005 due to higher employee
benefit costs associated with the increase in headcount,
increased pension and postretirement costs resulting from
changes in the assumptions used to determine our fiscal 2006
costs, higher facilities costs and higher pipeline integrity
costs.
As a result of the aforementioned factors, our pipeline and
storage segment operating income for the year ended
September 30, 2006 increased to $77.9 million from
$70.3 million for the year ended September 30, 2005.
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Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services, LLC, and Atmos Power
Systems, Inc. Through AES, we provide natural gas management
services to our utility operations, other than the Mid-Tex
Division. These services, which began April 2004, include
aggregating and purchasing gas supply, arranging transportation
and storage logistics and ultimately delivering the gas to our
utility service areas at competitive prices. The revenues of AES
represent charges to our utility divisions equal to the costs
incurred to provide those services. Through Atmos Power Systems,
Inc., we have constructed electric peaking power-generating
plants and associated facilities and have entered into
agreements to lease these plants.
Operating income for this segment primarily reflects the leasing
income associated with two sales-type lease transactions
completed in 2001 and 2002 and was essentially unchanged for the
year ended September 30, 2006 compared with the prior year.
Year
ended September 30, 2005 compared with year ended
September 30, 2004
Utility
segment
Utility gross profit increased to $907.4 million for the
year ended September 30, 2005 from $503.1 million for
the year ended September 30, 2004. Total throughput for our
utility business was 411.1 Bcf during the current year
compared to 246.0 Bcf in the prior year.
The increase in utility gross profit margin primarily reflects
the impact of the acquisition of the Mid-Tex Division resulting
in an increase in utility gross profit margin and total
throughput of $398.2 million and 174.3 Bcf. The
$6.1 million increase in the gross profit generated from
our other utility operations primarily reflects rate increases
in our Mississippi and West Texas divisions that were absent in
the prior year coupled with the recognition of a
$1.9 million refund to our customers in our Colorado
service area in the prior year. Offsetting these increases was a
$3.9 million reduction in gross profit in our Louisiana
Division due to the impact of Hurricane Katrina. Gross profit
margins, particularly in Louisiana, were also adversely impacted
by weather (as adjusted for jurisdictions with
weather-normalized operations) that was five percent warmer than
normal and one percent warmer than the prior year period.
Additionally, gross profit margin was adversely impacted by the
lack of cold weather in patterns sufficient to encourage
customers to increase their heat load consumption and lower
irrigation throughput in our West Texas and Colorado-Kansas
Divisions.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $671.0 million for the year ended
September 30, 2005 from $343.2 million for the year
ended September 30, 2004 primarily as a result of the
addition of the Mid-Tex Division. Excluding the impact of the
Mid-Tex Division, operating expenses for our other utility
operations increased $14.5 million primarily due to
$2.3 million associated with the effects of Hurricane
Katrina, a $7.7 million increase in taxes, other than
income, a $2.4 million increase in operation and
maintenance expense, including the provision for doubtful
accounts, and a $2.1 million increase in depreciation and
amortization. Included in taxes other than income taxes are
franchise and state gross receipts taxes which are paid by our
customers as a component of their monthly bills. Although these
amounts are offset in revenues through customer billings, timing
differences between when the expense is incurred and is
recovered may impact our net income on a temporary basis.
However, there is no permanent effect on net income.
As a result of the aforementioned factors, our utility segment
operating income for the year ended September 30, 2005
increased to $236.4 million from $159.9 million for
the year ended September 30, 2004.
Miscellaneous income increased to $6.8 million for the year
ended September 30, 2005 from $5.8 million for the
year ended September 30, 2004. The increase was
attributable to an increase in interest income earned
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on higher cash balances during the current year compared with
the prior year partially offset by the recognition of a
$0.8 million gain on the sale of a building during the year
ended September 30, 2004.
Interest charges allocated to the utility segment for the year
ended September 30, 2005 increased to $112.4 million
from $65.4 million for the year ended September 30,
2004. The increase was attributable to the interest expense
associated with the issuance of long-term debt to finance the
acquisition of the Mid-Tex Division in October 2004. On
June 30, 2005, we repaid $72.5 million in principal on
five series of our First Mortgage Bonds prior to their scheduled
maturities. The early repayment of these bonds resulted in
savings of $1.3 million in interest expense in fiscal 2005.
Natural
gas marketing segment
Our natural gas marketing segment’s gross profit margin was
comprised of the following for the years ended
September 30, 2005 and 2004:
Our natural gas marketing segment’s gross profit margin was
$62.0 million for the year ended September 30, 2005
compared to gross profit of $46.6 million for the year
ended September 30, 2004. Gross profit margin from our
natural gas marketing segment for the year ended September 30,
2005 included an unrealized loss of $26.0 million compared
with an unrealized loss of $2.8 million in the prior year.
Natural gas marketing sales volumes were 273.2 Bcf during
the year ended September 30, 2005 compared with
265.1 Bcf for the prior year. Excluding intersegment sales
volumes, natural gas marketing sales volumes were 238.1 Bcf
during the current year compared with 222.6 Bcf in the
prior year. The increase in consolidated natural gas marketing
sales volumes primarily was attributable to successfully
executed marketing strategies into new market areas.
The contribution to gross profit from our storage activities was
a gain of $14.0 million for the year ended
September 30, 2005 compared to a loss of $1.5 million
for the year ended September 30, 2004. The
$15.5 million improvement primarily was attributable to a
$29.9 million increase in the realized storage contribution
for the year ended September 30, 2005 compared to the prior
year due to more favorable arbitrage spread opportunities during
the current year, partially offset by increased storage fees
associated with 9.0 Bcf of newly contracted storage
capacity during the third quarter of fiscal 2005. Annual demand
charges for this new storage approximate $7.6 million. We
may further increase the amount of our storage capacity in the
future; therefore, the impact of price volatility on our
unrealized storage contribution could become more significant in
future periods.
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A $14.4 million decrease in the unrealized storage
contribution resulted from an unfavorable movement during the
year ended September 30, 2005 in the forward indices used
to value the storage financial instruments combined with greater
physical natural gas storage quantities at September 30,
2005 compared to the prior year also.
Our marketing activities contributed $48.0 million to our
gross profit for the year ended September 30, 2005 compared
to $48.2 million for the year ended September 30,
2004. The decrease in the marketing contribution primarily was
attributable to $12.0 million of unrealized
marked-to-market
losses associated with basis swaps that were put in place to
capture margins in certain volatile market areas. The increase
in unrealized
marked-to-market
losses was partially offset by an increase in our realized
marketing margins due to focusing our marketing efforts on
higher margin customers and successfully entering into new
market areas.
Operating expenses, which include operation and maintenance
expense, provision for doubtful accounts, depreciation and
amortization expense and taxes other than income taxes,
increased to $21.0 million for the year ended
September 30, 2005 from $18.9 million for the year
ended September 30, 2004. The increase in operating expense
was attributable primarily to an increase in labor costs due to
increased headcount and an increase in regulatory compliance
costs.
The increase in gross profit margin, combined with higher
operating expenses, resulted in an increase in our natural gas
marketing segment operating income to $41.0 million for the
year ended September 30, 2005 compared with operating
income of $27.7 million for the year ended
September 30, 2004.
Pipeline
and storage segment
Pipeline and storage gross profit increased to
$146.5 million for the year ended September 30, 2005
from $10.4 million for the year ended September 30,
2004. Total pipeline transportation volumes were 563.9 Bcf
during the year ended September 30, 2005 compared with
9.4 Bcf for the prior year. Excluding intersegment
transportation volumes, total pipeline transportation volumes
were 383.4 Bcf during the current year.
The increase in pipeline and storage gross profit margin
primarily reflects the impact of the acquisition of the Atmos
Pipeline — Texas Division resulting in an increase in
pipeline and storage gross profit margin and total
transportation volumes of $138.1 million and
375.6 Bcf. Also contributing to Atmos Pipeline —
Texas Division’s results were higher transportation and
related services margin due to significant basis differentials
at its three major Texas hubs. The $2.0 million decrease in
the gross profit generated by APS primarily reflects a decrease
in asset management fees received during fiscal 2005.
Operating expenses increased to $76.2 million for the year
ended September 30, 2005 from $5.1 million for the
year ended September 30, 2004 due to the addition of
$72.2 million in operating expenses associated with the
Atmos Pipeline — Texas Division. As the Atmos
Pipeline — Texas Division is a regulated entity,
franchise and state gross receipts taxes are paid by our
customers; thus, these amounts are offset in revenues through
customer billings and have no permanent effect on net income.
Included in operating expense was $8.9 million associated
with taxes other than income taxes, of which $8.3 million
was associated with our Atmos Pipeline — Texas
Division.
As a result of the aforementioned factors, our pipeline and
storage segment operating income for the year ended
September 30, 2005 increased to $70.3 million from
$5.3 million for the year ended September 30, 2004.
Interest charges allocated to this segment for the year ended
September 30, 2005 increased to $24.6 million from
$1.1 million for the year ended September 30, 2004.
The increase was attributable to the interest expense associated
with the issuance of long-term debt to finance the acquisition
of the Atmos Pipeline — Texas Division in October 2004.
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Operating income for our other nonutility segment primarily
reflects the leasing income associated with two sales-type lease
transactions completed in fiscal 2001 and 2002. The increase in
operating income during the year ended September 30, 2005
reflects the absence of a one-time charge of $0.4 million
associated with the wind-down of a noncore business during
fiscal 2004.
Miscellaneous income for the year ended September 30, 2005
was $2.6 million compared with $8.3 million for the
year ended September 30, 2004. The $5.7 million
decrease was attributable primarily to the recognition of a
$5.9 million pretax gain on the sale of all remaining
limited partnership interests in Heritage Propane Partners, L.P.
during fiscal 2004.
Our working capital and liquidity for capital expenditure 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 2007. These facilities are
described in greater detail below and in Note 6 to the
consolidated financial statements.
The following presents our capitalization as of
September 30, 2006 and 2005:
Total debt as a percentage of total capitalization, including
short-term debt, was 60.9 percent and 59.3 percent at
September 30, 2006 and 2005. The increase in the debt to
capitalization ratio was primarily attributable to an increase
in our short-term debt borrowings to fund our working capital
needs partially offset by current-year net income. Our ratio of
total debt to capitalization is typically greater during the
winter heating season as we make additional short-term
borrowings to fund natural gas purchases and meet our working
capital requirements. Within three to five years, we intend to
reduce our capitalization ratio to a target range of 50 to
55 percent through cash flow generated from operations,
continued issuance of new common stock under our Direct Stock
Purchase Plan and Retirement Savings Plan and access to the
equity capital markets.
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 services, the
demand for services, margin requirements resulting from
significant changes in commodity prices, operational risks and
other factors.
Year-over-year
changes in our operating cash flows are primarily attributable
to working capital changes within our utility segment resulting
from the impact of weather, the price of natural gas and the
timing of customer collections, payments for natural gas
purchases and deferred gas cost recoveries.
For the year ended September 30, 2006, we generated
operating cash flow of $311.4 million compared with
$386.9 million in fiscal 2005 and $270.7 million in
fiscal 2004. The significant factors impacting our operating
cash flow for the last three fiscal years are summarized below.
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Year
ended September 30, 2006
Fiscal 2006 operating cash flows reflect the adverse impact of
significantly higher natural gas prices.
Year-over-year,
unfavorable timing of payments for accounts payable and other
accrued liabilities reduced operating cash flow by
$523.0 million. Partially offsetting these outflows were
higher customer collections ($245.1 million) and reduced
payments for natural gas inventories ($102.1 million).
Additionally, favorable movements in the market indices used to
value our natural gas marketing segment risk management assets
and liabilities reduced the amount that we were required to
deposit in a margin account and therefore favorably affected
operating cash flow by $126.3 million.
Year
ended September 30, 2005
Fiscal 2005 operating cash flows reflect the effects of a
$49.6 million increase in net income and effective working
capital management partially offset by higher natural gas
prices. Working capital management efforts, which affected the
timing of payments for accounts payable and other accrued
liabilities, favorably affected operating cash flow by
$354.1 million. However, these efforts were partially
offset by reduced cash flow generated from accounts receivable
changes by $168.9 million, primarily attributable to higher
natural gas prices, and an increase in our natural gas
inventories attributable to a 13 percent
year-over-year
increase in natural gas prices coupled with increased natural
gas inventory levels, which reduced operating cash flow by
$81.8 million. Operating cash flow was also adversely
impacted by unfavorable movements in the indices used to value
our natural gas marketing segment risk management assets and
liabilities, which resulted in a net liability for the segment.
Accordingly, under the terms of the associated derivative
contracts, we were required to deposit $81.0 million into a
margin account.
Year
ended September 30, 2004
Fiscal 2004 operating cash flows were favorably impacted by
several items. Improved customer collections during fiscal 2004,
compared with the prior year, resulted in a $62.2 million
increase in operating cash flow. Further, cash used for natural
gas inventories decreased by $33.8 million compared with
the prior year. The decrease was attributable to lower
injections of natural gas into storage, partially offset by
higher prices. The reduction in the lag between the time period
when we purchase our natural gas and the period in which we can
include this cost in our gas rates improved operating cash flow
by $65.7 million. Changes in cash held on deposit in margin
accounts resulted in an increase in operating cash flow of
$25.6 million. This account represents deposits recorded to
collateralize certain of our financial derivatives purchased in
support of our natural gas marketing activities. The favorable
change was attributable to the fact that the fair value of
financial instruments held by AEM represented a net asset
position at September 30, 2004, which eliminated the need
to place cash in margin accounts. Finally, other working capital
and other changes improved operating cash flow by
$33.9 million. These changes primarily related to various
increases in deferred credits and other liabilities, other
current liabilities and income taxes payable partially offset by
lower deferred income tax expense as compared with the prior
year.
During the last three years, a substantial portion of our cash
resources was used to fund acquisitions and growth projects, our
ongoing construction program and improvements to information
systems. Our ongoing construction program enables us to provide
natural gas distribution services to our existing customer base,
to expand our natural gas distribution services into new
markets, to enhance the integrity of our pipelines and, more
recently, to expand our intrastate pipeline network. In
executing our current rate strategy, we are directing
discretionary capital spending to jurisdictions that permit us
to earn a return on our investment timely. Currently, our
Mid-Tex, Louisiana, Mississippi and West Texas utility divisions
and our Atmos Pipeline — Texas Division have rate
designs that provide the opportunity to include in their rate
base approved capital costs on a periodic basis without being
required to file a rate case.
For the year ended September 30, 2006, we incurred
$425.3 million for capital expenditures compared with
$333.2 million for the year ended September 30, 2005
and $190.3 million for the year ended
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September 30, 2004. The increase in capital expenditures in
fiscal 2006 primarily reflects increased spending associated
with our Dallas/Fort Worth Metroplex North Side Loop
project and other pipeline expansion projects in our Atmos
Pipeline — Texas Division, which were completed during
the fiscal 2006 third quarter. Increased capital spending in our
Mid-Tex Division for various projects also contributed to the
increase in our capital expenditures.
Our cash used for investing activities for the year ended
September 30, 2005 reflects the $1.9 billion cash paid
for the TXU Gas acquisition including related transaction costs
and expenses. Cash flow from investing activities for the year
ended September 30, 2004 reflects the receipt of
$27.9 million from the sale of our limited and general
partnership interests in USP and Heritage Propane Partners, L.P.
and from the sale of a building.
For the year ended September 30, 2006, our financing
activities provided $155.3 million in cash compared with
$1.7 billion and $80.4 million provided for the years
ended September 30, 2005 and 2004. Our significant
financing activities for the years ended September 30,
2006, 2005 and 2004 are summarized as follows:
During the year ended September 30, 2006 we issued
0.9 million shares of common stock which generated net
proceeds of $23.3 million. In addition, we granted
0.3 million shares of common stock under
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our 1998 Long-Term Incentive Plan to directors, officers and
other participants in the plan. The following table shows the
number of shares issued for the years ended September 30,
2006, 2005 and 2004:
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