e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
September 30, 2006
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from
to
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Commission file number 1-10042
Atmos Energy
Corporation
(Exact name of registrant as
specified in its charter)
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Texas and Virginia
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75-1743247
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(State or other jurisdiction
of
incorporation or organization)
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(IRS employer
identification no.)
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Three Lincoln Centre,
Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal
executive offices)
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75240
(Zip code)
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Registrants telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange
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Title of Each Class
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on Which Registered
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Common stock, No Par Value
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New York Stock Exchange
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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 registrants 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 registrants 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.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants 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.
GLOSSARY
OF KEY TERMS
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AEC |
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Atmos Energy Corporation
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AEH |
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Atmos Energy Holdings, Inc.
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AEM |
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Atmos Energy Marketing, LLC
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AES |
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Atmos Energy Services, LLC
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APB |
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Accounting Principles Board
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APS |
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Atmos Pipeline and Storage, LLC
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ATO |
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Trading symbol for Atmos Energy Corporation common stock on the
New York Stock Exchange
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Bcf |
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Billion cubic feet
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COSO |
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Committee of Sponsoring Organizations of the Treadway Commission
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EITF |
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Emerging Issues Task Force
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FASB |
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Financial Accounting Standards Board
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FERC |
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Federal Energy Regulatory Commission
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FIN |
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FASB Interpretation
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Fitch |
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Fitch Ratings, Ltd.
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FSP |
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FASB Staff Position
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GRIP |
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Gas Reliability Infrastructure Program
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Heritage |
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Heritage Propane Partners, L.P.
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iFERC |
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Inside FERC
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KPSC |
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Kentucky Public Service Commission
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LGS |
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Louisiana Gas Service Company and LGS Natural Gas Company, which
were acquired July 1, 2001
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LPSC |
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Louisiana Public Service Commission
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Mcf |
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Thousand cubic feet
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MDWQ |
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Maximum daily withdrawal quantity
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MMcf |
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Million cubic feet
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Moodys |
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Moodys Investor Services, Inc.
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MPSC |
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Mississippi Public Service Commission
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MVG |
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Mississippi Valley Gas Company, which was acquired
December 3, 2002
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NYMEX |
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New York Mercantile Exchange, Inc.
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NYSE |
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New York Stock Exchange
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RRC |
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Railroad Commission of Texas
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RSC |
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Rate Stabilization Clause
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S&P |
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Standard & Poors Corporation
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SEC |
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United States Securities and Exchange Commission
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SFAS |
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Statement of Financial Accounting Standards
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TXU Gas |
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TXU Gas Company, which was acquired on October 1, 2004
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USP |
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U.S. Propane, L.P.
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VCC |
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Virginia Corporation Commission
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WNA |
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Weather Normalization Adjustment
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3
PART I
The terms we, our, us,
Atmos and Atmos Energy refer to Atmos
Energy Corporation and its subsidiaries, unless the context
suggests otherwise.
Overview
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
countrys 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.
Operating
Segments
Our operations are divided into four segments:
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the utility segment, which includes our regulated natural gas
distribution and related sales operations,
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the natural gas marketing segment, which includes a variety of
nonregulated natural gas management services,
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the pipeline and storage segment, which includes our regulated
and nonregulated natural gas transmission and storage
services and
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the other nonutility segment, which includes all of our other
nonregulated nonutility operations.
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Strategy
Our overall strategy is to:
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deliver superior shareholder value,
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improve the quality and consistency of earnings growth, while
operating our natural gas utility and nonutility businesses
exceptionally well and
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enhance and strengthen a culture built on our core values.
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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:
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Atmos Energy Colorado-Kansas Division,
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Atmos Energy Kentucky Division,
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Atmos Energy Louisiana Division,
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Atmos Energy Mid-States Division,
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Atmos Energy Mid-Tex Division,
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Atmos Energy Mississippi Division and
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Atmos Energy West Texas Division.
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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:
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Georgia
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October May
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Kansas
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October May
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Kentucky
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November April
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Louisiana(1)
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December March
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Mid-Tex(1)
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October May
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Mississippi
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November April
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Tennessee
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November April
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Amarillo, Texas
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October May
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West Texas
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October May
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Lubbock, Texas
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October May
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Virginia
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January December
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Effective beginning with the
2006-2007
winter heating season. |
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 states 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 Divisions 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 Divisions 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
Divisions 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 states
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 divisions 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.
Natural
Gas Marketing Segment Overview
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.
AEMs 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.
Pipeline
and Storage Segment Overview
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 nations 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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Other
Nonutility Segment Overview
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.
10
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005(1)
|
|
|
2004
|
|
|
2003(1)
|
|
|
2002
|
|
|
METERS IN SERVICE, end of
year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
2,886,042
|
|
|
|
2,862,822
|
|
|
|
1,506,777
|
|
|
|
1,498,586
|
|
|
|
1,247,247
|
|
Commercial
|
|
|
275,577
|
|
|
|
274,536
|
|
|
|
151,381
|
|
|
|
151,008
|
|
|
|
122,156
|
|
Industrial
|
|
|
2,661
|
|
|
|
2,715
|
|
|
|
2,436
|
|
|
|
3,799
|
|
|
|
2,118
|
|
Agricultural
|
|
|
8,714
|
|
|
|
9,639
|
|
|
|
8,397
|
|
|
|
9,514
|
|
|
|
10,576
|
|
Public authority and other
|
|
|
8,205
|
|
|
|
8,128
|
|
|
|
10,145
|
|
|
|
9,891
|
|
|
|
7,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total meters
|
|
|
3,181,199
|
|
|
|
3,157,840
|
|
|
|
1,679,136
|
|
|
|
1,672,798
|
|
|
|
1,389,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
2,527
|
|
|
|
2,587
|
|
|
|
3,271
|
|
|
|
3,473
|
|
|
|
3,368
|
|
Percent of normal
|
|
|
87%
|
|
|
|
89%
|
|
|
|
96%
|
|
|
|
101%
|
|
|
|
94%
|
|
UTILITY SALES
VOLUMES
MMcf(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
144,780
|
|
|
|
162,016
|
|
|
|
92,208
|
|
|
|
97,953
|
|
|
|
77,386
|
|
Commercial
|
|
|
87,006
|
|
|
|
92,401
|
|
|
|
44,226
|
|
|
|
45,611
|
|
|
|
35,796
|
|
Industrial
|
|
|
26,161
|
|
|
|
29,434
|
|
|
|
22,330
|
|
|
|
23,738
|
|
|
|
14,499
|
|
Agricultural
|
|
|
5,629
|
|
|
|
3,348
|
|
|
|
4,642
|
|
|
|
7,884
|
|
|
|
10,988
|
|
Public authority and other
|
|
|
8,457
|
|
|
|
9,084
|
|
|
|
9,813
|
|
|
|
9,326
|
|
|
|
5,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales volumes
|
|
|
272,033
|
|
|
|
296,283
|
|
|
|
173,219
|
|
|
|
184,512
|
|
|
|
144,544
|
|
Utility transportation volumes
|
|
|
126,960
|
|
|
|
122,098
|
|
|
|
87,746
|
|
|
|
70,159
|
|
|
|
69,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility throughput
|
|
|
398,993
|
|
|
|
418,381
|
|
|
|
260,965
|
|
|
|
254,671
|
|
|
|
214,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILITY OPERATING REVENUES
(000s)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
2,068,736
|
|
|
$
|
1,791,172
|
|
|
$
|
923,773
|
|
|
$
|
873,375
|
|
|
$
|
535,981
|
|
Commercial
|
|
|
1,061,783
|
|
|
|
869,722
|
|
|
|
400,704
|
|
|
|
367,961
|
|
|
|
221,728
|
|
Industrial
|
|
|
276,186
|
|
|
|
229,649
|
|
|
|
155,336
|
|
|
|
151,969
|
|
|
|
70,164
|
|
Agricultural
|
|
|
40,664
|
|
|
|
27,889
|
|
|
|
31,851
|
|
|
|
48,625
|
|
|
|
37,951
|
|
Public authority and other
|
|
|
103,936
|
|
|
|
86,853
|
|
|
|
77,178
|
|
|
|
65,921
|
|
|
|
31,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility gas sales revenues
|
|
|
3,551,305
|
|
|
|
3,005,285
|
|
|
|
1,588,842
|
|
|
|
1,507,851
|
|
|
|
897,555
|
|
Transportation revenues
|
|
|
62,215
|
|
|
|
59,996
|
|
|
|
31,714
|
|
|
|
30,461
|
|
|
|
28,786
|
|
Other gas revenues
|
|
|
37,071
|
|
|
|
37,859
|
|
|
|
17,172
|
|
|
|
15,770
|
|
|
|
11,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility operating revenues
|
|
$
|
3,650,591
|
|
|
$
|
3,103,140
|
|
|
$
|
1,637,728
|
|
|
$
|
1,554,082
|
|
|
$
|
937,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility average transportation
revenue per Mcf
|
|
$
|
0.49
|
|
|
$
|
0.49
|
|
|
$
|
0.36
|
|
|
$
|
0.43
|
|
|
$
|
0.41
|
|
Utility average cost of gas per
Mcf sold
|
|
$
|
10.02
|
|
|
$
|
7.41
|
|
|
$
|
6.55
|
|
|
$
|
5.76
|
|
|
$
|
3.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees
|
|
|
4,402
|
|
|
|
4,327
|
|
|
|
2,742
|
|
|
|
2,817
|
|
|
|
2,255
|
|
See footnotes following these tables.
11
Utility
Sales and Statistical Data By Division
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
Colorado-
|
|
|
|
|
|
|
|
|
Mid-
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Kansas
|
|
|
Kentucky
|
|
|
Louisiana
|
|
|
States
|
|
|
Texas
|
|
|
Mississippi
|
|
|
Mid-Tex
|
|
|
Other(4)
|
|
|
Utility
|
|
|
METERS IN SERVICE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
213,566
|
|
|
|
158,408
|
|
|
|
330,694
|
|
|
|
277,998
|
|
|
|
273,520
|
|
|
|
241,406
|
|
|
|
1,390,450
|
|
|
|
|
|
|
|
2,886,042
|
|
Commercial
|
|
|
21,440
|
|
|
|
18,228
|
|
|
|
23,108
|
|
|
|
36,686
|
|
|
|
25,984
|
|
|
|
27,868
|
|
|
|
122,263
|
|
|
|
|
|
|
|
275,577
|
|
Industrial
|
|
|
84
|
|
|
|
240
|
|
|
|
|
|
|
|
681
|
|
|
|
808
|
|
|
|
643
|
|
|
|
205
|
|
|
|
|
|
|
|
2,661
|
|
Agricultural
|
|
|
312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,714
|
|
Public authority and other
|
|
|
543
|
|
|
|
1,637
|
|
|
|
|
|
|
|
1,034
|
|
|
|
2,166
|
|
|
|
2,825
|
|
|
|
|
|
|
|
|
|
|
|
8,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
235,945
|
|
|
|
178,513
|
|
|
|
353,802
|
|
|
|
316,399
|
|
|
|
310,880
|
|
|
|
272,742
|
|
|
|
1,512,918
|
|
|
|
|
|
|
|
3,181,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
5,466
|
|
|
|
4,349
|
|
|
|
1,319
|
|
|
|
3,515
|
|
|
|
3,561
|
|
|
|
2,757
|
|
|
|
1,697
|
|
|
|
|
|
|
|
2,527
|
|
Percent of normal
|
|
|
99%
|
|
|
|
100%
|
|
|
|
78%
|
|
|
|
95%
|
|
|
|
100%
|
|
|
|
102%
|
|
|
|
72%
|
|
|
|
|
|
|
|
87%
|
|
SALES VOLUMES
MMcf(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
15,113
|
|
|
|
9,249
|
|
|
|
12,131
|
|
|
|
15,065
|
|
|
|
15,609
|
|
|
|
12,601
|
|
|
|
65,012
|
|
|
|
|
|
|
|
144,780
|
|
Commercial
|
|
|
5,901
|
|
|
|
4,526
|
|
|
|
6,944
|
|
|
|
11,328
|
|
|
|
6,309
|
|
|
|
6,440
|
|
|
|
45,558
|
|
|
|
|
|
|
|
87,006
|
|
Industrial
|
|
|
419
|
|
|
|
1,830
|
|
|
|
|
|
|
|
6,945
|
|
|
|
3,933
|
|
|
|
8,250
|
|
|
|
4,784
|
|
|
|
|
|
|
|
26,161
|
|
Agricultural
|
|
|
619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,629
|
|
Public authority and other
|
|
|
1,390
|
|
|
|
1,237
|
|
|
|
|
|
|
|
226
|
|
|
|
1,962
|
|
|
|
3,642
|
|
|
|
|
|
|
|
|
|
|
|
8,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
23,442
|
|
|
|
16,842
|
|
|
|
19,075
|
|
|
|
33,564
|
|
|
|
32,823
|
|
|
|
30,933
|
|
|
|
115,354
|
|
|
|
|
|
|
|
272,033
|
|
Transportation Volumes
|
|
|
9,680
|
|
|
|
25,871
|
|
|
|
6,310
|
|
|
|
20,654
|
|
|
|
15,135
|
|
|
|
1,702
|
|
|
|
47,608
|
|
|
|
|
|
|
|
126,960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Throughput
|
|
|
33,122
|
|
|
|
42,713
|
|
|
|
25,385
|
|
|
|
54,218
|
|
|
|
47,958
|
|
|
|
32,635
|
|
|
|
162,962
|
|
|
|
|
|
|
|
398,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING MARGIN
(000s)(3)
|
|
$
|
71,000
|
|
|
$
|
50,271
|
|
|
$
|
98,502
|
|
|
$
|
106,742
|
|
|
$
|
93,693
|
|
|
$
|
92,515
|
|
|
$
|
412,334
|
|
|
$
|
|
|
|
$
|
925,057
|
|
OPERATING EXPENSES
(000s)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
$
|
28,235
|
|
|
$
|
19,874
|
|
|
$
|
40,741
|
|
|
$
|
38,148
|
|
|
$
|
33,332
|
|
|
$
|
44,533
|
|
|
$
|
154,412
|
|
|
$
|
(1,756
|
)
|
|
$
|
357,519
|
|
Depreciation and amortization
|
|
$
|
13,578
|
|
|
$
|
11,636
|
|
|
$
|
21,201
|
|
|
$
|
22,172
|
|
|
$
|
13,690
|
|
|
$
|
10,596
|
|
|
$
|
74,375
|
|
|
$
|
(2,755
|
)
|
|
$
|
164,493
|
|
Taxes, other than income
|
|
$
|
6,663
|
|
|
$
|
4,423
|
|
|
$
|
8,788
|
|
|
$
|
10,867
|
|
|
$
|
21,509
|
|
|
$
|
14,110
|
|
|
$
|
111,844
|
|
|
$
|
|
|
|
$
|
178,204
|
|
Impairment of long-lived assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
22,947
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
22,947
|
|
OPERATING INCOME
(000s)(3)
|
|
$
|
22,524
|
|
|
$
|
14,338
|
|
|
$
|
27,772
|
|
|
$
|
35,555
|
|
|
$
|
2,215
|
|
|
$
|
23,276
|
|
|
$
|
71,703
|
|
|
$
|
4,511
|
|
|
$
|
201,894
|
|
CAPITAL EXPENDITURES
(000s)
|
|
$
|
19,466
|
|
|
$
|
16,645
|
|
|
$
|
32,218
|
|
|
$
|
38,307
|
|
|
$
|
27,374
|
|
|
$
|
15,389
|
|
|
$
|
134,762
|
|
|
$
|
23,581
|
|
|
$
|
307,742
|
|
PROPERTY, PLANT AND EQUIPMENT,
NET (000s)
|
|
$
|
252,584
|
|
|
$
|
190,959
|
|
|
$
|
328,310
|
|
|
$
|
436,916
|
|
|
$
|
253,086
|
|
|
$
|
226,690
|
|
|
$
|
1,262,516
|
|
|
$
|
132,240
|
|
|
$
|
3,083,301
|
|
OTHER STATISTICS, at year
end
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miles of pipe
|
|
|
6,601
|
|
|
|
3,937
|
|
|
|
8,214
|
|
|
|
8,015
|
|
|
|
14,831
|
|
|
|
6,415
|
|
|
|
27,856
|
|
|
|
|
|
|
|
75,869
|
|
Employees
|
|
|
263
|
|
|
|
220
|
|
|
|
412
|
|
|
|
416
|
|
|
|
341
|
|
|
|
437
|
|
|
|
1,458
|
|
|
|
855
|
|
|
|
4,402
|
|
See footnotes following these tables.
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2005
|
|
|
|
Colorado-
|
|
|
|
|
|
|
|
|
Mid-
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Kansas
|
|
|
Kentucky
|
|
|
Louisiana
|
|
|
States
|
|
|
Texas
|
|
|
Mississippi
|
|
|
Mid-Tex
|
|
|
Other(4)
|
|
|
Utility
|
|
|
METERS IN SERVICE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
209,321
|
|
|
|
159,216
|
|
|
|
348,576
|
|
|
|
276,667
|
|
|
|
267,278
|
|
|
|
244,136
|
|
|
|
1,357,628
|
|
|
|
|
|
|
|
2,862,822
|
|
Commercial
|
|
|
20,914
|
|
|
|
18,350
|
|
|
|
23,850
|
|
|
|
36,519
|
|
|
|
25,410
|
|
|
|
28,350
|
|
|
|
121,143
|
|
|
|
|
|
|
|
274,536
|
|
Industrial
|
|
|
81
|
|
|
|
239
|
|
|
|
|
|
|
|
684
|
|
|
|
816
|
|
|
|
664
|
|
|
|
231
|
|
|
|
|
|
|
|
2,715
|
|
Agricultural
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,639
|
|
Public authority and other
|
|
|
476
|
|
|
|
1,650
|
|
|
|
|
|
|
|
1,066
|
|
|
|
2,139
|
|
|
|
2,797
|
|
|
|
|
|
|
|
|
|
|
|
8,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
231,071
|
|
|
|
179,455
|
|
|
|
372,426
|
|
|
|
314,936
|
|
|
|
305,003
|
|
|
|
275,947
|
|
|
|
1,479,002
|
|
|
|
|
|
|
|
3,157,840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEATING DEGREE
DAYS(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
5,437
|
|
|
|
4,241
|
|
|
|
1,301
|
|
|
|
3,510
|
|
|
|
3,536
|
|
|
|
2,583
|
|
|
|
1,904
|
|
|
|
|
|
|
|
2,587
|
|
Percent of normal
|
|
|
99%
|
|
|
|
98%
|
|
|
|
78%
|
|
|
|
93%
|
|
|
|
99%
|
|
|
|
96%
|
|
|
|
80%
|
|
|
|
|
|
|
|
89%
|
|
SALES VOLUMES
MMcf(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
16,404
|
|
|
|
10,741
|
|
|
|
13,134
|
|
|
|
16,222
|
|
|
|
19,292
|
|
|
|
12,985
|
|
|
|
73,238
|
|
|
|
|
|
|
|
162,016
|
|
Commercial
|
|
|
5,929
|
|
|
|
4,891
|
|
|
|
6,811
|
|
|
|
11,806
|
|
|
|
7,493
|
|
|
|
6,711
|
|
|
|
48,760
|
|
|
|
|
|
|
|
92,401
|
|
Industrial
|
|
|
338
|
|
|
|
1,858
|
|
|
|
|
|
|
|
8,205
|
|
|
|
4,477
|
|
|
|
9,057
|
|
|
|
5,499
|
|
|
|
|
|
|
|
29,434
|
|
Agricultural
|
|
|
246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,348
|
|
Public authority and other
|
|
|
1,355
|
|
|
|
1,396
|
|
|
|
|
|
|
|
241
|
|
|
|
2,296
|
|
|
|
3,796
|
|
|
|
|
|
|
|
|
|
|
|
9,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
24,272
|
|
|
|
18,886
|
|
|
|
19,945
|
|
|
|
36,474
|
|
|
|
36,660
|
|
|
|
32,549
|
|
|
|
127,497
|
|
|
|
|
|
|
|
296,283
|
|
Transportation Volumes
|
|
|
8,388
|
|
|
|
26,066
|
|
|
|
7,046
|
|
|
|
20,142
|
|
|
|
12,390
|
|
|
|
1,309
|
|
|
|
46,757
|
|
|
|
|
|
|
|
122,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Throughput
|
|
|
32,660
|
|
|
|
44,952
|
|
|
|
26,991
|
|
|
|
56,616
|
|
|
|
49,050
|
|
|
|
33,858
|
|
|
|
174,254
|
|
|
|
|
|
|
|
418,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING MARGIN
(000s)(3)
|
|
$
|
70,542
|
|
|
$
|
52,302
|
|
|
$
|
94,350
|
|
|
$
|
110,012
|
|
|
$
|
90,316
|
|
|
$
|
91,610
|
|
|
$
|
398,234
|
|
|
$
|
|
|
|
$
|
907,366
|
|
OPERATING EXPENSES
(000s)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
$
|
26,679
|
|
|
$
|
18,618
|
|
|
$
|
37,994
|
|
|
$
|
38,427
|
|
|
$
|
29,701
|
|
|
$
|
49,241
|
|
|
$
|
146,449
|
|
|
$
|
(515
|
)
|
|
$
|
346,594
|
|
Depreciation and amortization
|
|
$
|
13,693
|
|
|
$
|
11,739
|
|
|
$
|
21,911
|
|
|
$
|
23,615
|
|
|
$
|
13,249
|
|
|
$
|
10,830
|
|
|
$
|
64,460
|
|
|
$
|
|
|
|
$
|
159,497
|
|
Taxes, other than income
|
|
$
|
5,013
|
|
|
$
|
3,288
|
|
|
$
|
9,626
|
|
|
$
|
12,283
|
|
|
$
|
19,846
|
|
|
$
|
12,494
|
|
|
$
|
102,360
|
|
|
$
|
|
|
|
$
|
164,910
|
|
OPERATING INCOME
(000s)(3)
|
|
$
|
25,157
|
|
|
$
|
18,657
|
|
|
$
|
24,819
|
|
|
$
|
35,687
|
|
|
$
|
27,520
|
|
|
$
|
19,045
|
|
|
$
|
84,965
|
|
|
$
|
515
|
|
|
$
|
236,365
|
|
CAPITAL EXPENDITURES
(000s)
|
|
$
|
20,690
|
|
|
$
|
17,525
|
|
|
$
|
31,198
|
|
|
$
|
34,176
|
|
|
$
|
29,066
|
|
|
$
|
15,925
|
|
|
$
|
115,024
|
|
|
$
|
36,970
|
|
|
$
|
300,574
|
|
PROPERTY, PLANT AND EQUIPMENT,
NET (000s)
|
|
$
|
244,250
|
|
|
$
|
183,931
|
|
|
$
|
318,869
|
|
|
$
|
416,825
|
|
|
$
|
263,285
|
|
|
$
|
206,511
|
|
|
$
|
1,167,425
|
|
|
$
|
125,000
|
|
|
$
|
2,926,096
|
|
OTHER STATISTICS, at year
end
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Miles of pipe
|
|
|
6,530
|
|
|
|
3,908
|
|
|
|
8,151
|
|
|
|
7,958
|
|
|
|
15,000
|
|
|
|
6,356
|
|
|
|
33,701
|
|
|
|
|
|
|
|
81,604
|
|
Employees
|
|
|
267
|
|
|
|
236
|
|
|
|
421
|
|
|
|
412
|
|
|
|
346
|
|
|
|
467
|
|
|
|
1,398
|
|
|
|
780
|
|
|
|
4,327
|
|
See footnotes following these tables.
13
Natural
Gas Marketing, Pipeline and Storage and Other Nonutility
Operations Sales and Statistical Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
CUSTOMERS, end of
year Industrial
|
|
|
746
|
|
|
|
624
|
|
|
|
638
|
|
|
|
644
|
|
|
|
641
|
|
Municipal
|
|
|
73
|
|
|
|
69
|
|
|
|
80
|
|
|
|
94
|
|
|
|
101
|
|
Other
|
|
|
467
|
|
|
|
401
|
|
|
|
237
|
|
|
|
202
|
|
|
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,286
|
|
|
|
1,094
|
|
|
|
955
|
|
|
|
940
|
|
|
|
859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NATURAL GAS MARKETING SALES
VOLUMES
MMcf(3)
|
|
|
336,516
|
|
|
|
273,201
|
|
|
|
265,090
|
|
|
|
294,785
|
|
|
|
273,692
|
|
PIPELINE TRANSPORTATION
VOLUMES MMcf(3)
|
|
|
590,985
|
|
|
|
563,949
|
|
|
|
9,395
|
|
|
|
11,648
|
|
|
|
12,788
|
|
OPERATING REVENUES
(000s)(3)
Natural gas marketing
|
|
$
|
3,156,524
|
|
|
$
|
2,106,278
|
|
|
$
|
1,618,602
|
|
|
$
|
1,668,493
|
|
|
$
|
1,031,874
|
|
Pipeline and storage
|
|
|
160,567
|
|
|
|
153,289
|
|
|
|
19,758
|
|
|
|
20,298
|
|
|
|
18,720
|
|
Other nonutility
|
|
|
5,898
|
|
|
|
5,302
|
|
|
|
3,393
|
|
|
|
2,853
|
|
|
|
5,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
3,322,989
|
|
|
$
|
2,264,869
|
|
|
$
|
1,641,753
|
|
|
$
|
1,691,644
|
|
|
$
|
1,056,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employees, at year end
|
|
|
230
|
|
|
|
216
|
|
|
|
122
|
|
|
|
88
|
|
|
|
83
|
|
Notes to preceding tables:
|
|
|
(1) |
|
The operational and statistical information includes the
operations of the Mississippi Division since the
December 3, 2002 acquisition date and the Mid-Tex and Atmos
Pipeline Texas Divisions since the October 1,
2004 acquisition date. |
|
(2) |
|
A heating degree day is equivalent to each degree that the
average of the high and the low temperatures for a day is below
65 degrees. The colder the climate, the greater the number of
heating degree days. Heating degree days are used in the natural
gas industry to measure the relative coldness of weather and to
compare relative temperatures between one geographic area and
another. Normal degree days are based on
30-year
average National Weather Service data for selected locations.
For service areas that have weather normalized operations,
normal degree days are used instead of actual degree days in
computing the total number of heating degree days. |
|
(3) |
|
Sales volumes, revenues, operating margins, operating expense
and operating income reflect segment operations, including
intercompany sales and transportation amounts. |
|
(4) |
|
The Other column represents our utility shared services unit,
which provides administrative and other support to our seven
regulated utility divisions. Certain costs incurred by this unit
are not allocated to our utility divisions. |
Ratemaking
Activity
Overview
The method of determining regulated rates varies among the
states in which our natural gas utility divisions operate. The
regulators have the responsibility of ensuring that utilities
under their 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
14
address all of the utilitys 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 utilitys other costs,
(ii) represents a large component of the utilitys
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
|
|
|
|
Authorized
|
|
Authorized
|
|
|
|
|
Date of Last
|
|
Rate Base
|
|
Rate of
|
|
Return on
|
Division
|
|
Jurisdiction
|
|
Rate Action
|
|
(thousands)(1)
|
|
Return(1)
|
|
Equity(1)
|
|
Atmos Pipeline Texas
|
|
Texas
|
|
|
5/24/04
|
|
|
$
|
417,111
|
|
|
|
8.258
|
%
|
|
|
10.00
|
%
|
Colorado-Kansas
|
|
Colorado
|
|
|
7/1/05
|
|
|
|
84,711
|
|
|
|
8.95
|
%
|
|
|
11.25
|
%
|
|
|
Kansas
|
|
|
3/1/04
|
|
|
|
(2)
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
Kentucky
|
|
Kentucky
|
|
|
12/21/99
|
|
|
|
(2)
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
Louisiana
|
|
Trans LA
|
|
|
10/1/04
|
|
|
|
81,645
|
|
|
|
9.14
|
%
|
|
|
10.50% - 11.50%
|
|
|
|
LGS
|
|
|
10/1/04
|
|
|
|
170,358
|
|
|
|
9.23
|
%
|
|
|
10.88% - 11.50%
|
|
Mid-States
|
|
Georgia
|
|
|
12/20/05
|
|
|
|
62,380
|
|
|
|
7.57
|
%
|
|
|
10.13
|
%
|
|
|
Illinois
|
|
|
11/1/00
|
|
|
|
24,564
|
|
|
|
9.18
|
%
|
|
|
11.56
|
%
|
|
|
Iowa
|
|
|
3/1/01
|
|
|
|
5,000
|
|
|
|
(2
|
)
|
|
|
11.00
|
%
|
|
|
Missouri
|
|
|
10/14/95
|
|
|
|
(2)
|
|
|
|
10.58
|
%
|
|
|
12.15
|
%
|
|
|
Tennessee
|
|
|
11/15/95
|
|
|
|
111,970
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
Virginia
|
|
|
8/1/04
|
|
|
|
30,672
|
|
|
|
8.46% - 8.96%
|
|
|
|
9.50% -10.50%
|
|
Mid-Tex
|
|
Texas
|
|
|
5/24/04
|
|
|
|
769,721
|
|
|
|
8.258
|
%
|
|
|
10.00
|
%
|
Mississippi
|
|
Mississippi
|
|
|
1/1/05
|
|
|
|
196,801
|
|
|
|
8.23
|
%
|
|
|
9.80
|
%
|
West Texas
|
|
Amarillo
|
|
|
9/1/03
|
|
|
|
36,844
|
|
|
|
9.88
|
%
|
|
|
12.00
|
%
|
|
|
Lubbock
|
|
|
3/1/04
|
|
|
|
43,300
|
|
|
|
9.15
|
%
|
|
|
11.25
|
%
|
|
|
West Texas
|
|
|
5/1/04
|
|
|
|
87,500
|
|
|
|
8.77
|
%
|
|
|
10.50
|
%
|
See footnotes on the following page.
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
|
|
Authorized
|
|
Bad
|
|
|
|
Performance-
|
|
|
|
|
Date of Last
|
|
Debt/
|
|
Debt
|
|
|
|
Based Rate
|
Division
|
|
Jurisdiction
|
|
Rate Action
|
|
Equity Ratio
|
|
Rider(5)
|
|
WNA
|
|
Program(3)
|
|
Atmos Pipeline Texas
|
|
Texas
|
|
|
5/24/04
|
|
|
|
50/50
|
|
|
|
No
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Colorado-Kansas
|
|
Colorado
|
|
|
7/1/05
|
|
|
|
52/48
|
|
|
|
No
|
|
|
|
No
|
|
|
|
No
|
|
|
|
Kansas
|
|
|
3/1/04
|
|
|
|
(2)
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
Kentucky
|
|
Kentucky
|
|
|
12/21/99
|
|
|
|
(2)
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
Yes
|
|
Louisiana
|
|
Trans LA
|
|
|
10/1/04
|
|
|
|
50/50
|
|
|
|
No
|
|
|
|
(4)
|
|
|
|
No
|
|
|
|
LGS
|
|
|
10/1/04
|
|
|
|
53/47
|
|
|
|
No
|
|
|
|
(4)
|
|
|
|
No
|
|
Mid-States
|
|
Georgia
|
|
|
12/20/05
|
|
|
|
55/45
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
Illinois
|
|
|
11/1/00
|
|
|
|
67/33
|
|
|
|
No
|
|
|
|
No
|
|
|
|
No
|
|
|
|
Iowa
|
|
|
3/1/01
|
|
|
|
57/43
|
|
|
|
No
|
|
|
|
No
|
|
|
|
No
|
|
|
|
Missouri
|
|
|
10/14/95
|
|
|
|
(2)
|
|
|
|
No
|
|
|
|
No
|
|
|
|
No
|
|
|
|
Tennessee
|
|
|
11/15/95
|
|
|
|
56/44
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
Virginia
|
|
|
8/1/04
|
|
|
|
52/48
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
Mid-Tex
|
|
Texas
|
|
|
5/24/04
|
|
|
|
50/50
|
|
|
|
No
|
|
|
|
(4)
|
|
|
|
No
|
|
Mississippi
|
|
Mississippi
|
|
|
1/1/05
|
|
|
|
47/53
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
No
|
|
West Texas
|
|
Amarillo
|
|
|
9/1/03
|
|
|
|
50/50
|
|
|
|
Yes
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
Lubbock
|
|
|
3/1/04
|
|
|
|
50/50
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
West Texas
|
|
|
5/1/04
|
|
|
|
50/50
|
|
|
|
No
|
|
|
|
Yes
|
|
|
|
No
|
|
|
|
|
(1) |
|
The rate base and authorized rate of return presented in this
table are the rate base and rate of return from the last base
rate case for each jurisdiction. These rate bases and rates of
return are not necessarily indicative of current or future rate
bases or rates of return. |
|
(2) |
|
A rate base, rate of return, return on equity or debt/equity
ratio was not included in the respective state commissions
final decision. |
|
(3) |
|
The performance-based rate program provides incentives to
natural gas utilities to minimize purchased gas costs by
allowing the utility and its customers to share the purchased
gas cost savings. |
|
(4) |
|
During 2006, our Louisiana and Mid-Tex Divisions received
authorization to implement WNA beginning in the
2006-2007
winter heating season. |
|
(5) |
|
The bad debt rider allows us to recover from ratepayers the gas
cost portion of uncollectible accounts. |
Recent
Ratemaking Activity
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.
16
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Most Recent
|
|
|
|
|
|
Increase (Decrease) to Revenue
|
|
|
|
Effective
|
|
Most Recent
|
|
|
|
for the Year Ended September 30
|
|
Division
|
|
Date
|
|
Rate Action
|
|
Jurisdiction
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Atmos Pipeline Texas
|
|
8/1/06
|
|
GRIP(1)
|
|
Texas
|
|
$
|
5,205
|
|
|
$
|
1,802
|
|
|
$
|
|
|
Colorado-Kansas
|
|
4/1/04
|
|
Show Cause
|
|
Colorado
|
|
|
|
|
|
|
|
|
|
|
(1,900
|
)
|
|
|
1/1/06
|
|
Ad Valorem Tax
|
|
Kansas
|
|
|
1,565
|
|
|
|
|
|
|
|
|
|
|
|
3/1/04
|
|
Rate Case
|
|
Kansas
|
|
|
|
|
|
|
|
|
|
|
2,500
|
|
Louisiana
|
|
2/1/06
|
|
Stable Rate
Filing(2)
|
|
LGS
|
|
|
3,326
|
|
|
|
|
|
|
|
|
|
|
|
10/1/04
|
|
Stable Rate
Filing(2)
|
|
LGS
|
|
|
|
|
|
|
225
|
|
|
|
|
|
Mid-States
|
|
8/1/04
|
|
Rate Case
|
|
Virginia
|
|
|
|
|
|
|
|
|
|
|
372
|
|
|
|
12/20/05
|
|
Rate Case
|
|
Georgia
|
|
|
409
|
|
|
|
|
|
|
|
|
|
Mid-Tex
|
|
2/1/06
|
|
GRIP(1)
|
|
Texas
|
|
|
25,313
|
|
|
|
|
|
|
|
|
|
Mississippi
|
|
(3)
|
|
Stable Rate
Filing(2)
|
|
Mississippi
|
|
|
|
|
|
|
4,300
|
|
|
|
10,545
|
|
|
|
11/1/05
|
|
Rate Restructuring
|
|
Mississippi
|
|
|
(600
|
)
|
|
|
|
|
|
|
|
|
West Texas
|
|
12/1/05
|
|
GRIP(1)
|
|
Lubbock
|
|
|
1,263
|
|
|
|
|
|
|
|
|
|
|
|
3/1/04
|
|
Rate Case
|
|
Lubbock
|
|
|
|
|
|
|
|
|
|
|
1,525
|
|
|
|
3/1/06
|
|
GRIP(1)
|
|
West Texas
|
|
|
2,539
|
|
|
|
|
|
|
|
|
|
|
|
5/1/04
|
|
Rate Case
|
|
West Texas
|
|
|
|
|
|
|
|
|
|
|
3,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
39,020
|
|
|
$
|
6,327
|
|
|
$
|
16,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In 2003, the Texas Legislature approved the Gas Reliability
Infrastructure Program (GRIP) which allows natural gas utilities
the opportunity to include in their rate base annually approved
capital costs incurred in the prior calendar year. Natural gas
utilities that enter the program will be required to file a
complete rate case at least once every five years. |
|
(2) |
|
A stable rate filing is a regulatory mechanism designed to allow
us to refresh our rates on a periodic basis without filing a
formal rate case. |
|
(3) |
|
The MPSC had formerly required that we file for rate adjustments
every six months. Through May 2005, rate filings were made in
May and November of each year and the rate adjustments typically
became effective in June and December. See further discussion
under the recent ratemaking activity for our Atmos Energy
Mississippi Division below. |
Additionally, the following ratemaking efforts were initiated
during fiscal 2006 but had not been completed as of
September 30, 2006:
|
|
|
|
|
|
|
|
|
Division
|
|
Rate Action
|
|
Jurisdiction
|
|
Revenue Requested
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Louisiana
|
|
Stable Rate
Filing(1)
|
|
LGS
|
|
$
|
10,753
|
|
Mid-States
|
|
Rate Case
|
|
Missouri
|
|
|
3,396
|
|
|
|
Rate
Proceeding(2)
|
|
Tennessee
|
|
|
3,400
|
|
Mid-Tex
|
|
System-wide Case
|
|
Texas
|
|
|
60,844
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
78,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Louisiana Division has included the Rate Stabilization
Clause increase in rates. The increase is subject to refund,
pending final resolution of the Stable Rate Filing. |
|
(2) |
|
The Tennessee rate proceeding was settled in October 2006. See
below for information regarding the settlement. |
17
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 Divisions 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 Commissions ruling
in May 2003.
Atmos Energy Kentucky Division. In February
2006, the KPSC approved the Companys 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
18
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
TRAs 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 GPSCs 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 commissions 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
Generals 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 Staffs
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.
19
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 Divisions 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
Divisions 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 Divisions 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
20
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 Commissions 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
21
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.
Other
Regulation
Each of our utility divisions is regulated by various state or
local public utility authorities. We are also subject to
regulation by the United States Department of Transportation
with respect to safety requirements in the operation and
maintenance of our gas distribution facilities. Our distribution
operations are also subject to various state and federal laws
regulating environmental matters. From time to time we receive
inquiries regarding various environmental matters. We believe
that our properties and operations substantially comply with and
are operated in substantial conformity with applicable safety
and environmental statutes and regulations. There are no
administrative or judicial proceedings arising under
environmental quality statutes pending or known to be
contemplated by governmental agencies which would have a
material adverse effect on us or our operations. 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.
Competition
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,
22
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.
Employees
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.
Available
Information
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
Corporate
Governance
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
Companys Corporate Governance Guidelines and revised the
Companys 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 Companys 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:
We are
subject to regulation by each state in which we operate that
affect our operations and financial results.
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
23
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
operations are weather sensitive.
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.
The
concentration of our distribution, pipeline and storage
operations in the State of Texas have increased the exposure of
our operations and financial results to adverse weather,
economic conditions or regulatory decisions in
Texas.
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 Divisions
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 environmental regulation which could adversely affect
our operations or 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.
24
Our
operations are exposed to market risks that are beyond our
control which could adversely affect our financial
results.
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.
The
execution of our business plan could be affected by an inability
to access financial markets.
We rely upon access to both short-term and 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 & Poors Corporation
(S&P), Moodys Investors Services, Inc. (Moodys)
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
25
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
and increased gas costs could adversely impact our customer base
and customer collections and increase our level of
indebtedness.
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.
Our
operations are subject to increased competition.
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.
The
cost of providing pension and postretirement health care
benefits is subject to changes in pension fund values and
changing demographics and may have a material adverse effect on
our financial results.
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.
26
Our
growth in the future may be limited by the nature of our
business, which requires extensive capital
spending.
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.
Distributing
and storing natural gas involve risks that may result in
accidents and additional operating costs.
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 and terrorist activities and other actions could
adversely affect our operations or financial
results.
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.
|
|
ITEM 1B.
|
Unresolved
Staff Comments
|
Not applicable.
Distribution,
transmission and related assets
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.
27
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily
|
|
|
|
|
|
|
Cushion
|
|
|
Total
|
|
|
Delivery
|
|
|
|
Usable Capacity
|
|
|
Gas
|
|
|
Capacity
|
|
|
Capability
|
|
State
|
|
(Mcf)
|
|
|
(Mcf)(1)
|
|
|
(Mcf)
|
|
|
(Mcf)
|
|
|
Utility Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
4,442,696
|
|
|
|
6,322,283
|
|
|
|
10,764,979
|
|
|
|
109,100
|
|
Kansas
|
|
|
3,639,000
|
|
|
|
2,640,000
|
|
|
|
6,279,000
|
|
|
|
55,000
|
|
Mississippi
|
|
|
1,544,633
|
|
|
|
2,181,737
|
|
|
|
3,726,370
|
|
|
|
48,000
|
|
Georgia
|
|
|
450,000
|
|
|
|
50,000
|
|
|
|
500,000
|
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Utility Segment
|
|
|
10,076,329
|
|
|
|
11,194,020
|
|
|
|
21,270,349
|
|
|
|
242,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline and Storage
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
39,128,475
|
|
|
|
13,128,025
|
|
|
|
52,256,500
|
|
|
|
1,235,000
|
|
Kentucky
|
|
|
3,492,900
|
|
|
|
3,295,000
|
|
|
|
6,787,900
|
|
|
|
71,000
|
|
Louisiana
|
|
|
438,583
|
|
|
|
300,973
|
|
|
|
739,556
|
|
|
|
56,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Pipeline and Storage
Segment
|
|
|
43,059,958
|
|
|
|
16,723,998
|
|
|
|
59,783,956
|
|
|
|
1,362,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
53,136,287
|
|
|
|
27,918,018
|
|
|
|
81,054,305
|
|
|
|
1,604,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Cushion gas represents the volume of gas that must be retained
in a facility to maintain reservoir pressure. |
28
Additionally, we contract for storage service in underground
storage facilities on many of the interstate pipelines serving
us to supplement our proprietary storage capacity. The following
table summarizes our contracted storage capacity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
Maximum
|
|
|
Daily
|
|
|
|
|
|
Storage
|
|
|
Withdrawal
|
|
|
|
|
|
Quantity
|
|
|
Quantity
|
|
Division/Company
|
|
Contractor
|
|
(MMBtu)
|
|
|
(MMBtu)(1)
|
|
|
Utility Segment
|
|
|
|
|
|
|
|
|
|
|
Colorado-Kansas Division
|
|
Southern Star Central Pipeline
|
|
|
2,719,101
|
|
|
|
82,397
|
|
|
|
Tenaska Marketing Ventures
|
|
|
1,000,000
|
|
|
|
10,400
|
|
|
|
Colorado Interstate Gas Company
|
|
|
422,142
|
|
|
|
12,985
|
|
|
|
Kinder Morgan, Inc.
|
|
|
67,500
|
|
|
|
1,500
|
|
|
|
Centerpoint Energy Gas Transmission
|
|
|
28,500
|
|
|
|
950
|
|
Kentucky Division
|
|
Texas Gas Transmission
|
|
|
3,841,150
|
|
|
|
41,060
|
|
|
|
Tennessee Gas Pipeline Company
|
|
|
1,313,538
|
|
|
|
22,698
|
|
Louisiana Division
|
|
Gulf South
|
|
|
1,978,020
|
|
|
|
98,901
|
|
|
|
Jefferson Island
Storage & Hub
|
|
|
600,000
|
|
|
|
60,000
|
|
|
|
Acadian Natural Gas Company
|
|
|
33,276
|
|
|
|
2,234
|
|
|
|
Tennessee Gas Pipeline Company
|
|
|
18,776
|
|
|
|
329
|
|
|
|
Southern Natural Gas Company
|
|
|
12,945
|
|
|
|
261
|
|
|
|
Trunkline Gas Company
|
|
|
3,105
|
|
|
|
41
|
|
Mid-States Division
|
|
Atmos Energy Marketing
|
|
|
1,993,543
|
|
|
|
16,634
|
|
|
|
Southern Natural Gas Company
|
|
|
1,453,265
|
|
|
|
29,345
|
|
|
|
Panhandle Eastern Pipeline
|
|
|
1,035,462
|
|
|
|
15,721
|
|
|
|
Tennessee Gas Pipeline Company
|
|
|
835,674
|
|
|
|
20,000
|
|
|
|
Texas Eastern Transmission Company
|
|
|
753,969
|
|
|
|
11,303
|
|
|
|
Gallagher Drilling
Company(2)
|
|
|
640,000
|
|
|
|
5,000
|
|
|
|
ANR Pipeline Company
|
|
|
629,480
|
|
|
|
11,200
|
|
|
|
Dominion
|
|
|
609,008
|
|
|
|
8,136
|
|
|
|
Transco
|
|
|
568,674
|
|
|
|
12,710
|
|
|
|
Virginia Gas Pipeline Company
|
|
|
380,000
|
|
|
|
23,000
|
|
|
|
East Tennessee
|
|
|
339,900
|
|
|
|
52,633
|
|
|
|
Natural Gas Pipeline Company
|
|
|
312,750
|
|
|
|
5,580
|
|
|
|
Texas Gas Transmission
|
|
|
239,576
|
|
|
|
7,495
|
|
|
|
CMS Trunkline Gas Company
|
|
|
220,455
|
|
|
|
2,940
|
|
|
|
MRT Energy Marketing
|
|
|
137,493
|
|
|
|
2,395
|
|
Mississippi Division
|
|
Gulf South
|
|
|
1,237,500
|
|
|
|
61,875
|
|
|
|
Southern Natural Gas Company
|
|
|
1,049,436
|
|
|
|
21,191
|
|
|
|
Texas Gas Transmission
|
|
|
826,390
|
|
|
|
36,420
|
|
|
|
Texas Eastern
|
|
|
518,220
|
|
|
|
8,637
|
|
|
|
Atmos Energy Marketing
|
|
|
400,000
|
|
|
|
40,000
|
|
|
|
Trunkline Gas Company
|
|
|
24,840
|
|
|
|
331
|
|
|
|
Tennessee Gas Pipeline Company
|
|
|
3,394
|
|
|
|
113
|
|
West Texas Division
|
|
ONEOK Texas Gas Storage LLP
|
|
|
1,125,000
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Utility Segment
|
|
|
|
|
27,372,082
|
|
|
|
776,415
|
|
|
See footnotes on the following
page.
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
Maximum
|
|
|
Daily
|
|
|
|
|
|
Storage
|
|
|
Withdrawal
|
|
|
|
|
|
Quantity
|
|
|
Quantity
|
|
Division/Company
|
|
Contractor
|
|
(MMBtu)
|
|
|
(MMBtu)(1)
|
|
|
Natural Gas Marketing
Segment
|
|
|
|
|
|
|
|
|
|
|
Atmos Energy Marketing, LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf South
|
|
|
5,992,015
|
|
|
|
85,686
|
|
|
|
Egan
|
|
|
1,500,000
|
|
|
|
90,000
|
|
|
|
Atmos Pipeline Texas
|
|
|
1,000,000
|
|
|
|
24,000
|
|
|
|
Texas Eastern Transmission Company
|
|
|
544,841
|
|
|
|
5,532
|
|
|
|
East Tennessee
|
|
|
250,000
|
|
|
|
12,500
|
|
|
|
National Fuel
|
|
|
223,080
|
|
|
|
2,028
|
|
|
|
Virginia Gas Pipeline Company
|
|
|
170,000
|
|
|
|
17,000
|
|
|
|
Dominion
|
|
|
56,910
|
|
|
|
929
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Marketing
Segment
|
|
|
|
|
9,736,846
|
|
|
|
237,675
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline and Storage
Segment
|
|
|
|
|
|
|
|
|
|
|
Trans Louisiana Gas Pipeline,
Inc.
|
|
Gulf South Pipeline Company
|
|
|
750,000
|
|
|
|
30,000
|
|
|
|
Bridgeline Gas Distribution LLC
|
|
|
300,000
|
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Pipeline and Storage
Segment
|
|
|
|
|
1,050,000
|
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contracted Storage
Capacity
|
|
|
|
|
38,158,928
|
|
|
|
1,074,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate
depending upon the season and the month. Unless otherwise noted,
MDWQ amounts represent the MDWQ amounts as of November 1,
which is the beginning of the winter heating season. |
|
(2) |
|
We contract for storage service in two underground storage
facilities, Wiseman and Ellis, from this company. |
Other
facilities
Our utility segment owns and operates one propane peak shaving
plant with a total capacity of approximately 180,000 gallons
that can produce an equivalent of approximately 3,300 Mcf
daily.
Offices
Our administrative offices are consolidated in 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.
|
|
ITEM 3.
|
Legal
Proceedings
|
See Note 13 to the consolidated financial statements.
|
|
ITEM 4.
|
Submission
of Matters to a Vote of Security Holders
|
No matters were submitted to a vote of security holders during
the fourth quarter of fiscal 2006.
30
EXECUTIVE
OFFICERS OF THE REGISTRANT
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years of
|
|
|
|
Name
|
|
Age
|
|
|
Service
|
|
|
Office Currently Held
|
|
Robert W. Best
|
|
|
59
|
|
|
|
9
|
|
|
Chairman, President and Chief
Executive Officer
|
Kim R. Cocklin
|
|
|
55
|
|
|
|
|
|
|
Senior Vice President, Utility
Operations
|
R. Earl Fischer
|
|
|
67
|
|
|
|
44
|
|
|
Senior Vice President, Utility
Operations
|
Louis P. Gregory
|
|
|
51
|
|
|
|
6
|
|
|
Senior Vice President and General
Counsel
|
Mark H. Johnson
|
|
|
47
|
|
|
|
5
|
|
|
Senior Vice President, Nonutility
Operations and President, Atmos Energy Marketing, LLC
|
Wynn D. McGregor
|
|
|
53
|
|
|
|
18
|
|
|
Senior Vice President, Human
Resources
|
John P. Reddy
|
|
|
53
|
|
|
|
8
|
|
|
Senior Vice President and Chief
Financial 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
Marketings 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.
31
PART II
|
|
ITEM 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Paid
|
|
|
High
|
|
|
Low
|
|
|
Paid
|
|
|
Quarter ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31
|
|
$
|
28.36
|
|
|
$
|
25.79
|
|
|
$
|
.315
|
|
|
$
|
27.43
|
|
|
$
|
24.85
|
|
|
$
|
.310
|
|
March 31
|
|
|
27.00
|
|
|
|
26.10
|
|
|
|
.315
|
|
|
|
29.09
|
|
|
|
26.19
|
|
|
|
.310
|
|
June 30
|
|
|
27.91
|
|
|
|
26.00
|
|
|
|
.315
|
|
|
|
28.87
|
|
|
|
25.94
|
|
|
|
.310
|
|
September 30
|
|
|
29.11
|
|
|
|
27.96
|
|
|
|
.315
|
|
|
|
29.76
|
|
|
|
28.23
|
|
|
|
.310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.26
|
|
|
|
|
|
|
|
|
|
|
$
|
1.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Number of Securities Remaining
|
|
|
|
Securities to be Issued
|
|
|
Weighted-Average
|
|
|
Available for Future Issuance
|
|
|
|
Upon Exercise of
|
|
|
Exercise Price of
|
|
|
Under Equity Compensation
|
|
|
|
Outstanding Options,
|
|
|
Outstanding Options,
|
|
|
Plans (Excluding Securities
|
|
|
|
Warrants and Rights
|
|
|
Warrants and Rights
|
|
|
Reflected in Column (a))
|
|
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans
approved by security holders:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Incentive Plan
|
|
|
1,017,152
|
|
|
$
|
22.57
|
|
|
|
731,745
|
|
Long-Term Stock Plan for the
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-States Division
|
|
|
|
|
|
|
|
|
|
|
168,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity compensation plans
approved by security holders
|
|
|
1,017,152
|
|
|
|
22.57
|
|
|
|
900,295
|
|
Equity compensation plans not
approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,017,152
|
|
|
$
|
22.57
|
|
|
|
900,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
ITEM 6.
|
Selected
Financial Data
|
The following table sets forth selected financial data of the
Company and should be read in conjunction with the consolidated
financial statements included herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006(1)
|
|
|
2005(2)
|
|
|
2004(3)
|
|
|
2003(4)
|
|
|
2002
|
|
|
|
(In thousands, except per share data and ratios)
|
|
|
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
6,152,363
|
|
|
$
|
4,961,873
|
|
|
$
|
2,920,037
|
|
|
$
|
2,799,916
|
|
|
$
|
1,650,964
|
|
Gross profit
|
|
|
1,216,570
|
|
|
|
1,117,637
|
|
|
|
562,191
|
|
|
|
534,976
|
|
|
|
431,140
|
|
Operating
expenses(1)
|
|
|
833,954
|
|
|
|
768,982
|
|
|
|
368,496
|
|
|
|
347,136
|
|
|
|
275,809
|
|
Operating income
|
|
|
382,616
|
|
|
|
348,655
|
|
|
|
193,695
|
|
|
|
187,840
|
|
|
|
155,331
|
|
Miscellaneous income
(expense)(3)
|
|
|
881
|
|
|
|
2,021
|
|
|
|
9,507
|
|
|
|
2,191
|
|
|
|
(1,321
|
)
|
Interest charges
|
|
|
146,607
|
|
|
|
132,658
|
|
|
|
65,437
|
|
|
|
63,660
|
|
|
|
59,174
|
|
Income before income taxes and
cumulative effect of accounting change
|
|
|
236,890
|
|
|
|
218,018
|
|
|
|
137,765
|
|
|
|
126,371
|
|
|
|
94,836
|
|
Cumulative effect of accounting
change, net income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,773
|
)
|
|
|
|
|
Income tax expense
|
|
|
89,153
|
|
|
|
82,233
|
|
|
|
51,538
|
|
|
|
46,910
|
|
|
|
35,180
|
|
Net income
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
|
$
|
71,688
|
|
|
$
|
59,656
|
|
Weighted average diluted shares
outstanding
|
|
|
81,390
|
|
|
|
79,012
|
|
|
|
54,416
|
|
|
|
46,496
|
|
|
|
41,250
|
|
Diluted net income per share
|
|
$
|
1.82
|
|
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
$
|
1.54
|
|
|
$
|
1.45
|
|
Cash flows from operations
|
|
|
311,449
|
|
|
|
386,944
|
|
|
|
270,734
|
|
|
|
49,541
|
|
|
|
297,395
|
|
Cash dividends paid per share
|
|
$
|
1.26
|
|
|
$
|
1.24
|
|
|
$
|
1.22
|
|
|
$
|
1.20
|
|
|
$
|
1.18
|
|
Total utility throughput (MMcf)
|
|
|
393,995
|
|
|
|
411,134
|
|
|
|
246,033
|
|
|
|
247,965
|
|
|
|
208,541
|
|
Total natural gas marketing sales
volumes (MMcf)
|
|
|
283,962
|
|
|
|
238,097
|
|
|
|
222,572
|
|
|
|
225,961
|
|
|
|
204,027
|
|
Total pipeline transportation
volumes (MMcf)
|
|
|
420,217
|
|
|
|
383,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Condition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and
equipment(5)
|
|
$
|
3,629,156
|
|
|
$
|
3,374,367
|
|
|
$
|
1,722,521
|
|
|
$
|
1,624,394
|
|
|
$
|
1,380,070
|
|
Working
capital(5)
|
|
|
(1,616
|
)
|
|
|
151,675
|
|
|
|
283,310
|
|
|
|
16,248
|
|
|
|
(139,150
|
)
|
Total
assets(5)(6)
|
|
|
5,719,547
|
|
|
|
5,653,527
|
|
|
|
2,912,627
|
|
|
|
2,625,495
|
|
|
|
2,059,631
|
|
Short-term debt, inclusive of
current maturities of long-term debt
|
|
|
385,602
|
|
|
|
148,073
|
|
|
|
5,908
|
|
|
|
127,940
|
|
|
|
167,771
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
1,648,098
|
|
|
|
1,602,422
|
|
|
|
1,133,459
|
|
|
|
857,517
|
|
|
|
573,235
|
|
Long-term debt (excluding current
maturities)
|
|
|
2,180,362
|
|
|
|
2,183,104
|
|
|
|
861,311
|
|
|
|
862,500
|
|
|
|
668,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,828,460
|
|
|
|
3,785,526
|
|
|
|
1,994,770
|
|
|
|
1,720,017
|
|
|
|
1,242,194
|
|
Capital expenditures
|
|
|
425,324
|
|
|
|
333,183
|
|
|
|
190,285
|
|
|
|
159,439
|
|
|
|
132,252
|
|
Financial Ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
ratio(6)
|
|
|
39.1%
|
|
|
|
40.7%
|
|
|
|
56.7%
|
|
|
|
46.4%
|
|
|
|
40.7%
|
|
Return on average
shareholders
equity(7)
|
|
|
8.9%
|
|
|
|
9.0%
|
|
|
|
9.1%
|
|
|
|
9.9%
|
|
|
|
9.9%
|
|
See footnotes on the following page.
33
|
|
|
(1) |
|
Financial results for 2006 include a $22.9 million pre-tax
loss for the impairment of the West Texas Divisions
irrigation assets. |
|
(2) |
|
Financial results for 2005 include the results of the Mid-Tex
Division and Atmos Pipeline Texas Division from
October 1, 2004, the date of acquisition. |
|
(3) |
|
Financial results for 2004 include a $5.9 million pre-tax
gain on the sale of our interest in U.S. Propane, L.P. and
Heritage Propane Partners, L.P. |
|
(4) |
|
Financial results for fiscal 2003 include the results of MVG
from December 3, 2002, the date of acquisition. |
|
(5) |
|
Beginning in 2004, we reclassified our regulatory cost of
removal obligation from accumulated depreciation to a liability.
The amounts presented above for property, plant and equipment,
working capital and total assets reflect this reclassification
for all periods presented. These reclassifications did not
impact our financial position, results of operations or cash
flows as of and for the years ended September 30, 2003 and
2002. |
|
(6) |
|
The capitalization ratio is calculated by dividing
shareholders equity by the sum of total capitalization and
short-term debt, inclusive of current maturities of long-term
debt. Beginning in 2004 we reclassified our original issue
discount costs from deferred charges and other assets to
long-term debt. This reclassification did not materially impact
our capitalization or our capitalization ratio as of
September 30, 2003 and 2002. |
|
(7) |
|
The return on average shareholders equity is calculated by
dividing current year net income by the average of
shareholders equity for the previous five quarters. |
The following table presents a condensed income statement by
segment for the year ended September 30, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
3,649,851
|
|
|
$
|
2,418,856
|
|
|
$
|
81,857
|
|
|
$
|
1,799
|
|
|
$
|
|
|
|
$
|
6,152,363
|
|
Intersegment revenues
|
|
|
740
|
|
|
|
737,668
|
|
|
|
78,710
|
|
|
|
4,099
|
|
|
|
(821,217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,650,591
|
|
|
|
3,156,524
|
|
|
|
160,567
|
|
|
|
5,898
|
|
|
|
(821,217
|
)
|
|
|
6,152,363
|
|
Purchased gas cost
|
|
|
2,725,534
|
|
|
|
3,025,897
|
|
|
|
838
|
|
|
|
|
|
|
|
(816,476
|
)
|
|
|
4,935,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
925,057
|
|
|
|
130,627
|
|
|
|
159,729
|
|
|
|
5,898
|
|
|
|
(4,741
|
)
|
|
|
1,216,570
|
|
Operating expenses
|
|
|
723,163
|
|
|
|
28,392
|
|
|
|
81,871
|
|
|
|
5,506
|
|
|
|
(4,978
|
)
|
|
|
833,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
201,894
|
|
|
|
102,235
|
|
|
|
77,858
|
|
|
|
392
|
|
|
|
237
|
|
|
|
382,616
|
|
Miscellaneous income
|
|
|
9,506
|
|
|
|
2,598
|
|
|
|
2,554
|
|
|
|
4,151
|
|
|
|
(17,928
|
)
|
|
|
881
|
|
Interest charges
|
|
|
126,489
|
|
|
|
8,510
|
|
|
|
25,331
|
|
|
|
3,968
|
|
|
|
(17,691
|
)
|
|
|
146,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
84,911
|
|
|
|
96,323
|
|
|
|
55,081
|
|
|
|
575
|
|
|
|
|
|
|
|
236,890
|
|
Income tax expense
|
|
|
31,909
|
|
|
|
37,757
|
|
|
|
19,457
|
|
|
|
30
|
|
|
|
|
|
|
|
89,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
53,002
|
|
|
$
|
58,566
|
|
|
$
|
35,624
|
|
|
$
|
545
|
|
|
$
|
|
|
|
$
|
147,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
307,742
|
|
|
$
|
909
|
|
|
$
|
116,673
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
425,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
ITEM 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
INTRODUCTION
This section provides managements 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
managements 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.
Cautionary
Statement for the Purposes of the Safe Harbor under the Private
Securities Litigation Reform Act of 1995
The statements contained in this Annual Report on
Form 10-K
may contain forward-looking statements within the
meaning of Section 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.
OVERVIEW
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
35
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 utility segment net income decreased $28.1 million
during the year ended September 30, 2006 compared with the
year ended September 30, 2005. The decrease primarily
resulted from the impact of weather, as adjusted for
jurisdictions with weather-normalized rates, that was two
percent warmer than the prior-year period and 13 percent
warmer than normal, coupled with higher operating expenses.
Utility segment results also reflect a $14.6 million net of
tax charge associated with the impairment of the West Texas
Divisions irrigation assets.
|
|
|
|
During fiscal 2006, our Louisiana and Mid-Tex divisions received
WNA in their rate designs that will go into effect in fiscal
2007. After receiving 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.
|
|
|
|
Our natural gas marketing segment net income increased
$35.2 million during the year ended September 30, 2006
compared with the year ended September 30, 2005. The
increase in natural gas marketing net income primarily reflects
an increase in our unrealized margin of $43.2 million and
increased realized margins due to our ability to capture higher
margins in a volatile natural gas market. These increases were
partially offset by a $7.4 million increase in operating
expenses and increased interest charges resulting from increased
short-term borrowings to fund working capital needs.
|
|
|
|
Our pipeline and storage segment net income increased
$5.0 million during the year ended September 30, 2006
compared with the year ended September 30, 2005. Increased
gross profit margin resulting from higher transportation and
related services margins coupled with increased throughput on
our Atmos Pipeline-Texas system and Atmos Pipeline &
Storage, LLCs ability to capture more favorable arbitrage
spreads in its asset management contracts were partially offset
by higher operating expenses.
|
|
|
|
Our capitalization ratio at September 30, 2006 was
60.9 percent compared with 59.3 percent at
September 30, 2005 reflecting the impact of increased
short-term debt borrowings to fund working capital needs
partially offset by current-year net income.
|
|
|
|
For the year ended September 30, 2006, we generated
$311.4 million in operating cash flow compared with
$386.9 million for the year ended September 30, 2005,
reflecting the adverse impact of high natural gas costs on our
working capital.
|
|
|
|
Capital expenditures increased to $425.3 million from
$333.2 million primarily reflecting increased capital
spending for various pipeline expansion projects in our Atmos
Pipeline Texas Division.
|
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.
36
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 utilitys 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 utilitys other costs,
(ii) represents a large component of the utilitys
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
customers 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
37
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
38
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 units 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
39
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 Moodys 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 years 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.
40
RESULTS
OF OPERATIONS
The following table presents our financial highlights for the
three fiscal years ended September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, unless otherwise noted)
|
|
|
Operating revenues
|
|
$
|
6,152,363
|
|
|
$
|
4,961,873
|
|
|
$
|
2,920,037
|
|
Gross profit
|
|
|
1,216,570
|
|
|
|
1,117,637
|
|
|
|
562,191
|
|
Operating expenses
|
|
|
833,954
|
|
|
|
768,982
|
|
|
|
368,496
|
|
Operating income
|
|
|
382,616
|
|
|
|
348,655
|
|
|
|
193,695
|
|
Miscellaneous income
|
|
|
881
|
|
|
|
2,021
|
|
|
|
9,507
|
|
Interest charges
|
|
|
146,607
|
|
|
|
132,658
|
|
|
|
65,437
|
|
Income before income taxes
|
|
|
236,890
|
|
|
|
218,018
|
|
|
|
137,765
|
|
Income tax expense
|
|
|
89,153
|
|
|
|
82,233
|
|
|
|
51,538
|
|
Net income
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility sales volumes
MMcf
|
|
|
272,033
|
|
|
|
296,283
|
|
|
|
173,219
|
|
Utility transportation
volumes MMcf
|
|
|
121,962
|
|
|
|
114,851
|
|
|
|
72,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility
throughput MMcf
|
|
|
393,995
|
|
|
|
411,134
|
|
|
|
246,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas marketing sales
volumes MMcf
|
|
|
283,962
|
|
|
|
238,097
|
|
|
|
222,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation
volumes MMcf
|
|
|
420,217
|
|
|
|
383,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating Degree
Days (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual (weighted average)
|
|
|
2,527
|
|
|
|
2,587
|
|
|
|
3,271
|
|
Percent of normal
|
|
|
87%
|
|
|
|
89%
|
|
|
|
96%
|
|
Consolidated utility average
transportation revenue per Mcf
|
|
$
|
0.50
|
|
|
$
|
0.51
|
|
|
$
|
0.42
|
|
Consolidated utility average cost
of gas per Mcf sold
|
|
$
|
10.02
|
|
|
$
|
7.41
|
|
|
$
|
6.55
|
|
|
|
|
(1) |
|
Adjusted for service areas that have weather normalized
operations. For service areas that have weather normalized
operations, normal degree days are used instead of actual degree
days in computing the total number of heating degree days. |
41
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Heating
|
|
|
|
|
|
Heating
|
|
|
|
|
|
Heating
|
|
|
|
|
|
|
Degree Days
|
|
|
|
|
|
Degree Days
|
|
|
|
|
|
Degree Days
|
|
|
|
Operating
|
|
|
Percent of
|
|
|
Operating
|
|
|
Percent of
|
|
|
Operating
|
|
|
Percent of
|
|
|
|
Income
|
|
|
Normal(1)
|
|
|
Income
|
|
|
Normal(1)
|
|
|
Income
|
|
|
Normal(1)
|
|
|
|
(In thousands, except degree day information)
|
|
|
Colorado-Kansas
|
|
$
|
22,524
|
|
|
|
99
|
%
|
|
$
|
25,157
|
|
|
|
99
|
%
|
|
$
|
20,876
|
|
|
|
99
|
%
|
Kentucky
|
|
|
14,338
|
|
|
|
100
|
%
|
|
|
18,657
|
|
|
|
98
|
%
|
|
|
22,738
|
|
|
|
98
|
%
|
Louisiana
|
|
|
27,772
|
|
|
|
78
|
%
|
|
|
24,819
|
|
|
|
78
|
%
|
|
|
40,762
|
|
|
|
93
|
%
|
Mid-States
|
|
|
35,555
|
|
|
|
95
|
%
|
|
|
35,687
|
|
|
|
93
|
%
|
|
|
38,778
|
|
|
|
95
|
%
|
Mid-Tex
|
|
|
71,703
|
|
|
|
72
|
%
|
|
|
84,965
|
|
|
|
80
|
%
|
|
|
|
|
|
|
|
|
Mississippi
|
|
|
23,276
|
|
|
|
102
|
%
|
|
|
19,045
|
|
|
|
96
|
%
|
|
|
18,709
|
|
|
|
101
|
%
|
West Texas
|
|
|
2,215
|
|
|
|
100
|
%
|
|
|
27,520
|
|
|
|
99
|
%
|
|
|
22,090
|
|
|
|
90
|
%
|
Other
|
|
|
4,511
|
|
|
|
|
|
|
|
515
|
|
|
|
|
|
|
|
(4,063
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
201,894
|
|
|
|
87
|
%
|
|
|
236,365
|
|
|
|
89
|
%
|
|
|
159,890
|
|
|
|
96
|
%
|
Natural gas marketing segment
|
|
|
102,235
|
|
|
|
|
|
|
|
40,985
|
|
|
|
|
|
|
|
27,726
|
|
|
|
|
|
Pipeline and storage segment
|
|
|
77,858
|
|
|
|
|
|
|
|
70,286
|
|
|
|
|
|
|
|
5,293
|
|
|
|
|
|
Other nonutility segment
|
|
|
629
|
|
|
|
|
|
|
|
1,019
|
|
|
|
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
$
|
382,616
|
|
|
|
87
|
%
|
|
$
|
348,655
|
|
|
|
89
|
%
|
|
$
|
193,695
|
|
|
|
96
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Adjusted for service areas that have weather-normalized
operations. For service areas that have weather normalized
operations, normal degree days are used instead of actual degree
days in computing the total number of heating degree days. |
Year
ended September 30, 2006 compared with year ended
September 30, 2005
Utility
segment
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
42
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 jurisdictions 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
Divisions 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
Divisions 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.
Operating
income
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 LPSCs 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
43
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 Divisions
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
Divisions 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.
44
Miscellaneous
income
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
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.
Natural
gas marketing segment
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.
Operating
income
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.
45
Our natural gas marketing segments gross profit margin was
comprised of the following for the year ended September 30,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except physical position)
|
|
|
Storage Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
$
|
26,225
|
|
|
$
|
28,008
|
|
Unrealized margin
|
|
|
(1,293
|
)
|
|
|
(14,007
|
)
|
|
|
|
|
|
|
|
|
|
Total Storage Activities
|
|
|
24,932
|
|
|
|
14,001
|
|
Marketing Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
|
87,236
|
|
|
|
59,971
|
|
Unrealized margin
|
|
|
18,459
|
|
|
|
(11,999
|
)
|
|
|
|
|
|
|
|
|
|
Total Marketing Activities
|
|
|
105,695
|
|
|
|
47,972
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
130,627
|
|
|
$
|
61,973
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
14.5
|
|
|
|
6.9
|
|
|
|
|
|
|
|
|
|
|
Our natural gas marketing segments 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
46
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
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.
Pipeline
and storage segment
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 nations
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.
47
Operating
income
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 segments gross profit margin was
comprised of the following components for the year ended
September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Mid-Tex transportation
|
|
$
|
69,925
|
|
|
$
|
70,089
|
|
Third party transportation
|
|
|
58,490
|
|
|
|
55,376
|
|
Asset management fees
|
|
|
10,333
|
|
|
|
8,559
|
|
Storage and park and lend services
|
|
|
11,297
|
|
|
|
7,451
|
|
Unrealized gains (losses)
|
|
|
3,350
|
|
|
|
(4,730
|
)
|
Other
|
|
|
6,334
|
|
|
|
9,733
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
159,729
|
|
|
$
|
146,478
|
|
|
|
|
|
|
|
|
|
|
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 pipelines 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
pipelines 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 segments 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.
48
Other
nonutility segment
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
Operating
income
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
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
49
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
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
Operating
income
Our natural gas marketing segments gross profit margin was
comprised of the following for the years ended
September 30, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except physical position)
|
|
|
Storage Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
$
|
28,008
|
|
|
$
|
(1,900
|
)
|
Unrealized margin
|
|
|
(14,007
|
)
|
|
|
357
|
|
|
|
|
|
|
|
|
|
|
Total Storage Activities
|
|
|
14,001
|
|
|
|
(1,543
|
)
|
Marketing Activities
|
|
|
|
|
|
|
|
|
Realized margin
|
|
|
59,971
|
|
|
|
51,347
|
|
Unrealized margin
|
|
|
(11,999
|
)
|
|
|
(3,173
|
)
|
|
|
|
|
|
|
|
|
|
Total Marketing Activities
|
|
|
47,972
|
|
|
|
48,174
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
$
|
61,973
|
|
|
$
|
46,631
|
|
|
|
|
|
|
|
|
|
|
Net physical position (Bcf)
|
|
|
6.9
|
|
|
|
5.4
|
|
|
|
|
|
|
|
|
|
|
Our natural gas marketing segments 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.
50
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
Operating
income
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 Divisions 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
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.
51
Other
nonutility segment
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.
LIQUIDITY
AND CAPITAL RESOURCES
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.
Capitalization
The following presents our capitalization as of
September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except percentages)
|
|
|
Short-term debt
|
|
$
|
382,416
|
|
|
|
9.1
|
%
|
|
$
|
144,809
|
|
|
|
3.7
|
%
|
Long-term debt
|
|
|
2,183,548
|
|
|
|
51.8
|
%
|
|
|
2,186,368
|
|
|
|
55.6
|
%
|
Shareholders equity
|
|
|
1,648,098
|
|
|
|
39.1
|
%
|
|
|
1,602,422
|
|
|
|
40.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization, including
short-term debt
|
|
$
|
4,214,062
|
|
|
|
100.0
|
%
|
|
$
|
3,933,599
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Cash
Flows
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.
Cash
flows from operating activities
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.
52
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.
Cash
flows from investing activities
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
53
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.
Cash
flows from financing activities
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:
|
|
|
|
|
In October 2004, we sold 16.1 million shares of common
stock, including the underwriters exercise of their
overallotment option of 2.1 million shares, under a shelf
registration statement declared effective in September 2004,
generating net proceeds of $382 million. Additionally, we
issued $1.39 billion of senior unsecured debt under our
shelf registration statement with an initial weighted average
effective interest rate on these notes of 4.76 percent. The
net proceeds from these issuances, combined with the net
proceeds from our July 2004 common stock offering were used to
finance the acquisition of our Mid-Tex and Atmos
Pipeline Texas divisions and settle Treasury lock
agreements, into which we entered to fix the Treasury yield
component of the interest cost of financing associated with
$875 million of the $1.39 billion long-term debt we
issued in October 2004 to fund the acquisition.
|
|
|
|
During the years ended September 30, 2006 and 2005, we
increased our borrowings under our short-term facilities by
$237.6 million and $144.8 million whereas during the
year ended September 30, 2004, we repaid a net
$118.6 million under our short-term facilities. Net
borrowings under our short-term facilities during fiscal 2006
and 2005 reflect the impact of seasonal natural gas purchases
and the effect of higher natural gas prices than in prior years.
|
|
|
|
We repaid $3.3 million of long-term debt during the year
ended September 30, 2006 compared with $103.4 million
during the year ended September 30, 2005 and
$9.7 million during the year ended September 30, 2004.
Fiscal 2005 payments reflected the repayment of
$72.5 million of our First Mortgage Bonds. In connection
with this repayment we paid a $25.0 million make-whole
premium in accordance with the terms of the agreements and
accrued interest of approximately $1.0 million. In
accordance with regulatory requirements, the premium has been
deferred and will be recognized over the remaining original
lives of the First Mortgage Bonds that were repaid. The early
repayment of these bonds resulted in interest savings of
$4.8 million and $1.3 million in fiscal 2006 and 2005.
|
|
|
|
During the year ended September 30, 2006, we paid
$102.3 million in cash dividends compared with dividend
payments of $99.0 million and $66.7 million for the
years ended September 30, 2005 and 2004. The increase in
dividends paid over the prior year reflects an increase in the
dividend rate from $1.24 per share during the year ended
September 30, 2005 to $1.26 per share during the year
ended September 30, 2006 combined with new share issuances
under our various plans.
|
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
54
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Shares issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct stock purchase plan
|
|
|
387,833
|
|
|
|
450,212
|
|
|
|
556,856
|
|
Retirement savings plan
|
|
|
442,635
|
|
|
|
441,350
|
|
|
|
320,313
|
|
1998 Long-term incentive plan
|
|
|
366,905
|
|
|
|
745,788
|
|
|
|
498,230
|
|
Long-term stock plan for
Mid-States Division
|
|
|
300
|
|
|
|
|
|
|
|
6,000
|
|
Outside directors
stock-for-fee
plan
|
|
|
2,442
|
|
|
|
2,341
|
|
|
|
3,133
|
|
October 2004 Offering
|
|
|
|
|
|
|
16,100,000
|
|
|
|
|
|
July 2004 Offering
|
|
|
|
|
|
|
|
|
|
|
9,939,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shares issued
|
|
|
1,200,115
|
|
|
|
17,739,691
|
|
|
|
11,323,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shelf
Registration
In December 2001, we filed a registration statement with the
Securities and Exchange Commission (SEC) to issue, from time to
time, up to $600.0 million in new common stock
and/or debt.
The registration statement was declared effective by the SEC in
January 2002. In July 2004, we sold 9.9 million shares of
our common stock, including the underwriters exercise of
their overallotment option, which exhausted the remaining
availability under this registration statement.
In August 2004, we filed a registration statement with the SEC
to issue, from time to time, up to $2.2 billion in new
common stock
and/or debt,
which became effective in September 2004. In October 2004, we
sold 16.1 million common shares, including the
underwriters exercise of their overallotment option of
2.1 million shares, under this registration statement,
generating net proceeds of $382.5 million before other
offering costs. Additionally, we issued $1.39 billion of
senior unsecured debt under the registration statement. After
issuing the debt and equity in October 2004, we had
approximately $401.5 million of availability remaining
under this registration statement. However, we are no longer
allowed to issue securities under that registration statement by
applicable state regulatory commissions since we are in the
process of securing their approval to issue a total of
$900 million in securities under a new shelf registration
statement, including the remaining $401.5 million of
capacity carried over from the currently effective registration
statement. We intend to file this new registration statement
with the SEC in the near future.
Credit
Facilities
As of September 30, 2006, we maintained three short-term
committed credit facilities totaling $918 million. We also
maintain one uncommitted credit facility totaling
$25 million and, through AEM, a second uncommitted credit
facility that can provide up to $580 million. Borrowings
under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the banks. Our credit capacity and
the amount of unused borrowing capacity are affected by the
seasonal nature of the natural gas business and our short-term
borrowing requirements, which are typically highest during
colder winter months. Our working capital needs can vary
significantly due to changes in the price of natural gas charged
by suppliers and the increased gas supplies required to meet
customers needs during periods of cold weather. Our cash
needs for working capital have increased substantially as a
result of the significant increase in the price of natural gas.
In October 2005, our $600 million
364-day
committed credit facility expired and was replaced with a
$600 million three-year revolving credit facility. In
addition, in November 2005, we entered into a new
$300 million
364-day
revolving credit facility with substantially the same terms as
our $600 million credit facility.
55
In November 2006, we renewed our $300 million
364-day
revolving credit facility and were in the process of replacing
our three-year $600 million facility with a five-year
$600 million revolving credit facility. Both facilities are
being renewed with substantially the same terms as their
predecessor facilities.
In April 2006, our $18 million committed unsecured credit
facility was renewed for one year with no material changes to
its terms and pricing. At September 30, 2006,
$3.1 million was outstanding under this facility.
As of September 30, 2006, the amount available to us under
these credit facilities, net of outstanding letters of credit,
was $609.0 million. We believe these credit facilities,
combined with our operating cash flows will be sufficient to
fund our increased working capital needs. These facilities are
described in further detail in Note 6 to the consolidated
financial statements.
In November 2005, AEM amended its uncommitted demand working
capital credit facility to increase the amount of credit
available from $250 million to a maximum of
$580 million. In March 2006, AEM amended and extended this
uncommitted demand working capital credit facility to March
2007. At September 30, 2006, there were no borrowings
outstanding under this facility.
Credit
Ratings
Our credit ratings directly affect our ability to obtain
short-term and long-term financing, in addition to the cost of
such financing. In determining our credit ratings, the rating
agencies consider a number of quantitative factors, including
debt to total capitalization, operating cash flow relative to
outstanding debt, operating cash flow coverage of interest and
pension liabilities and funding status. In addition, the rating
agencies consider qualitative factors such as consistency of our
earnings over time, the quality of our management and business
strategy, the risks associated with our utility and nonutility
businesses and the regulatory structures that govern our rates
in the states where we operate.
Our debt is rated by three rating agencies: Standard &
Poors Corporation (S&P), Moodys Investors
Services, Inc. (Moodys) and Fitch Ratings, Ltd. (Fitch).
Our current debt ratings are all considered investment grade and
are as follows:
|
|
|
|
|
|
|
|
|
S&P
|
|
Moodys
|
|
Fitch
|
|
Long-term debt
|
|
BBB
|
|
Baa3
|
|
BBB+
|
Commercial paper
|
|
A-2
|
|
P-3
|
|
F-2
|
Currently, with respect to our unsecured senior long-term debt,
S&P, Moodys and Fitch maintain their stable outlook.
None of our ratings is currently under review.
A credit rating is not a recommendation to buy, sell or hold
securities. The highest investment grade credit rating for
S&P is AAA, Moodys is Aaa and Fitch is AAA. The lowest
investment grade credit rating for S&P is BBB−,
Moodys is Baa3 and Fitch is BBB−. Our credit ratings
may be revised or withdrawn at any time by the rating agencies,
and each rating should be evaluated independent of any other
rating. There can be no assurance that a rating will remain in
effect for any given period of time or that a rating will not be
lowered, or withdrawn entirely, by a rating agency if, in its
judgment, circumstances so warrant.
Debt
Covenants
We were in compliance with all of our debt covenants as of
September 30, 2006. If we do not comply with our debt
covenants, we may be required to repay our outstanding balances
on demand, provide additional collateral or take other
corrective actions. Our two public debt indentures relating to
our senior notes and debentures, as well as both our revolving
credit agreements, each contain a default provision that is
triggered if outstanding indebtedness arising out of any other
credit agreements in amounts ranging from in excess of
$15 million to in excess of $100 million becomes due
by acceleration or is not paid at maturity. In addition,
AEMs credit agreement contains a cross-default provision
whereby AEM would be in default if it defaults on other
indebtedness, as defined, by at least $250 thousand in the
aggregate. Additionally, this agreement
56
contains a provision that would limit the amount of credit
available if Atmos were downgraded below an S&P rating of
BBB and a Moodys rating of Baa2.
Except as described above, we have no triggering events in our
debt instruments that are tied to changes in specified credit
ratings or stock price, nor have we entered into any
transactions that would require us to issue equity based on our
credit rating or other triggering events.
Additional information concerning our debt covenants and how we
complied with those covenants is included in Note 6 to the
consolidated financial statements.
Contractual
Obligations and Commercial Commitments
The following tables provide information about contractual
obligations and commercial commitments at September 30,
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Contractual
Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt(1)
|
|
$
|
2,186,878
|
|
|
$
|
3,186
|
|
|
$
|
305,865
|
|
|
$
|
762,762
|
|
|
$
|
1,115,065
|
|
Short-term
debt(1)
|
|
|
382,416
|
|
|
|
382,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
charges(2)
|
|
|
1,028,096
|
|
|
|
121,511
|
|
|
|
207,939
|
|
|
|
164,964
|
|
|
|
533,682
|
|
Gas purchase
commitments(3)
|
|
|
708,217
|
|
|
|
560,461
|
|
|
|
110,793
|
|
|
|
17,035
|
|
|
|
19,928
|
|
Capital lease
obligations(4)
|
|
|
2,777
|
|
|
|
433
|
|
|
|
673
|
|
|
|
477
|
|
|
|
1,194
|
|
Operating
leases(4)
|
|
|
176,806
|
|
|
|
15,959
|
|
|
|
30,157
|
|
|
|
26,912
|
|
|
|
103,778
|
|
Demand fees for contracted
storage(5)
|
|
|
17,989
|
|
|
|
8,832
|
|
|
|
7,257
|
|
|
|
1,900
|
|
|
|
|
|
Demand fees for contracted
transportation(6)
|
|
|
27,818
|
|
|
|
4,269
|
|
|
|
5,944
|
|
|
|
5,788
|
|
|
|
11,817
|
|
Derivative
obligations(7)
|
|
|
30,945
|
|
|
|
30,669
|
|
|
|
276
|
|
|
|
|
|
|
|
|
|
Postretirement benefit plan
contributions(8)
|
|
|
145,198
|
|
|
|
11,408
|
|
|
|
21,584
|
|
|
|
26,141
|
|
|
|
86,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
4,707,140
|
|
|
$
|
1,139,144
|
|
|
$
|
690,488
|
|
|
$
|
1,005,979
|
|
|
$
|
1,871,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See Note 6 to the consolidated financial statements. |
|
(2) |
|
Interest charges were calculated using the stated rate for each
debt issuance, or in the case of floating rate debt, the rate
that was in effect as of September 30, 2006. |
|
(3) |
|
Gas purchase commitments were determined based upon
contractually determined volumes at prices estimated based upon
the index specified in the contract, adjusted for estimated
basis differentials and contractual discounts as of
September 30, 2006. |
|
(4) |
|
See Note 14 to the consolidated financial statements. |
|
(5) |
|
Represents third party contractual demand fees for contracted
storage in our natural gas marketing and other utility segments.
Contractual demand fees for contracted storage for our utility
segment are excluded as these costs are fully recoverable
through our purchase gas adjustment mechanisms. |
|
(6) |
|
Represents third party contractual demand fees for
transportation in our natural gas marketing segment. |
|
(7) |
|
Represents liabilities for natural gas commodity derivative
contracts that were valued as of September 30, 2006. The
ultimate settlement amounts of these remaining liabilities are
unknown because they are subject to continuing market risk until
the derivative contracts are settled. |
|
(8) |
|
Represents expected contributions to our postretirement benefit
plans. |
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At September 30, 2006, AEM was committed
to purchase 61.7 Bcf within one year, 51.2 Bcf between
one to three years and 0.8 Bcf after three years under
indexed
57
contracts. AEM was committed to purchase 2.4 Bcf within one
year and 0.1 Bcf within one to three years under fixed
price contracts with prices ranging from $3.40 to
$12.00 per Mcf.
With the exception of our Mid-Tex Division, our utility segment
maintains supply contracts with several vendors that generally
cover a period of up to one year. Commitments for estimated base
gas volumes are established under these contracts on a monthly
basis at contractually negotiated prices. Commitments for
incremental daily purchases are made as necessary during the
month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
prices. The estimated commitments under these contract terms as
of September 30, 2006 are reflected in the table above.
In May 2006, we announced plans to form a joint venture with a
local natural gas producer to construct a natural gas gathering
system in Eastern Kentucky that will originate in Floyd County,
Kentucky, and extend north approximately 60 miles to
interconnect with the Tennessee Gas Pipeline in Carter County,
Kentucky. Tennessee Gas Pipelines interstate system
delivers natural gas to the northeastern United States,
including New York City and Boston. 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. More than a dozen
other producers have signed memoranda of understanding to commit
gas volumes to the new system and to enter into agreements on
commercially reasonable terms.
As currently designed, the project is expected to cost between
$75 million to $80 million. In October 2006, FERC
issued a declaratory order finding that the Straight Creek
Project will be exempt from FERC jurisdiction. Upon receiving
all required regulatory approvals, construction is expected to
begin in the first half of fiscal 2007, with operations expected
to begin in fiscal 2008. Final terms of the joint venture are
still being negotiated; however, we anticipate that we will have
the ability to consolidate the joint venture.
Risk
Management Activities
We conduct risk management activities through our utility,
natural gas marketing and pipeline and storage segments. In our
utility segment, we use a combination of storage, fixed physical
contracts and fixed financial contracts to reduce our exposure
to unusually large winter-period gas price increases. In our
natural gas marketing and pipeline and storage segments, we
manage our exposure to the risk of natural gas price changes and
lock in our gross profit margin through a combination of storage
and financial derivatives, including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. To the extent our inventory cost and actual
sales and actual purchases do not correlate with the changes in
the market indices we use in our hedges, we could experience
ineffectiveness or the hedges may no longer meet the accounting
requirements for hedge accounting, resulting in the derivatives
being treated as mark to market instruments through earnings.
In our natural gas marketing segment, hedge ineffectiveness
resulting from natural gas market price differences between the
locations of the hedged inventory and the delivery location
specified in the hedge instruments (referred to as basis
ineffectiveness) for both fair value and cash flow hedges was an
unrealized gain of approximately $35.5 million for the year
ended September 30, 2006 and an unrealized loss of
approximately $5.4 million and $1.1 million for the
years ended September 30, 2005 and 2004. Actual hedge
ineffectiveness resulting from the timing of settlement of
physical contracts and the settlement of the derivative
instruments (referred to as timing ineffectiveness) resulted in
an unrealized gain of approximately $4.4 million and
$0.5 million for the years ended September 30, 2006
and 2004 and an unrealized loss of approximately
$2.2 million for the year ended September 30, 2005.
In our pipeline and storage segment, timing ineffectiveness
resulted in an unrealized loss of approximately
$4.7 million and less than $0.1 million for the years
ended September 30, 2006 and 2004 and an unrealized gain of
approximately $5.2 million for the year ended
September 30, 2005.
Finally, 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-
58
term debt. These Treasury lock agreements were settled in
October 2004 with a net $43.8 million payment to the
counterparties. Approximately $11.6 million of the
$43.8 million obligation is being recognized as a component
of interest expense over a five year period from the date of
settlement, and the remaining amount, approximately
$32.2 million, is being recognized as a component of
interest expense over a ten year period from the date of
settlement. Our risk management activities and related
accounting treatment are described in further detail in
Note 5 to the consolidated financial statements.
We record our derivatives as a component of risk management
assets and liabilities, which are classified as current or
noncurrent based upon the anticipated settlement date of the
underlying derivative. Substantially all of our derivative
financial instruments are valued using external market quotes
and indices. The following table shows the components of the
change in fair value of our utility and natural gas marketing
derivative contract activities for the year ended
September 30, 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Fair value of contracts at
September 30, 2005
|
|
$
|
93,310
|
|
|
$
|
(61,898
|
)
|
Contracts realized/settled
|
|
|
25,461
|
|
|
|
11,106
|
|
Fair value of new contracts
|
|
|
(18,651
|
)
|
|
|
|
|
Other changes in value
|
|
|
(127,329
|
)
|
|
|
65,795
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts at
September 30, 2006
|
|
$
|
(27,209
|
)
|
|
$
|
15,003
|
|
|
|
|
|
|
|
|
|
|
The fair value of our utility and natural gas marketing
derivative contracts at September 30, 2006, is segregated
below by time period and fair value source.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts at September 30, 2006
|
|
|
|
Maturity in Years
|
|
|
|
|
|
|
Less
|
|
|
|
|
|
|
|
|
Greater
|
|
|
Total Fair
|
|
Source of Fair Value
|
|
Than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
Than 5
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Prices actively quoted
|
|
$
|
(17,421
|
)
|
|
$
|
7,122
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(10,299
|
)
|
Prices provided by other external
sources
|
|
|
(440
|
)
|
|
|
(936
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,376
|
)
|
Prices based on models and other
valuation methods
|
|
|
(255
|
)
|
|
|
(276
|
)
|
|
|
|
|
|
|
|
|
|
|
(531
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
$
|
(18,116
|
)
|
|
$
|
5,910
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(12,206
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Storage
and Hedging Outlook
AEM participates in transactions in which it seeks to find and
profit from pricing differences that occur over time. AEM
purchases physical natural gas and then sells financial
contracts at favorable prices to lock in a gross profit margin.
AEM is able to capture gross profit margin through the arbitrage
of pricing differences in various locations and by recognizing
pricing differences that occur over time.
Natural gas inventory is marked to market at the end of each
month with changes in fair value recognized as unrealized gains
and losses in the period of change. Effective October 1,
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 to
the Company on the date of adoption. Derivatives associated with
our natural gas inventory, which are designated as fair value
hedges, are marked to market each month based upon the NYMEX
price with changes in fair value recognized as unrealized gains
and losses in the period of change. The changes in the
difference between the indices used to mark to market our
physical inventory (Gas Daily) and the related fair-value hedge
(NYMEX) are reported as a component of revenue and can result in
volatility in our reported net income. Over time, gains and
losses on the sale of storage gas inventory will be offset by
gains and losses on the fair-value hedges; therefore, the
economic gross profit AEM captured in the original transaction
remains essentially unchanged.
59
AEM continually manages its positions to enhance the future
economic profit it captured in the original transaction.
Therefore, AEM may change its scheduled injection and withdrawal
plans from one time period to another based on market conditions
or adjust the amount of storage capacity it holds on a
discretionary basis in an effort to achieve this objective. AEM
monitors the impacts of these profit optimization efforts by
estimating the gross profit that it captured and expects to
collect through the purchase and sale of physical natural gas
and the associated financial derivatives, which we refer to as
the economic gross profit. The economic gross profit, combined
with the effect of unrealized gains or losses recognized in the
financial statements in prior periods, provides a measure of the
gross profit that could occur in future periods if AEMs
optimization efforts are fully successful. The following table
presents AEMs economic gross profit and its potential
gross profit for the last three fiscal years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated Net
|
|
|
|
|
|
|
|
|
|
Economic
|
|
|
Unrealized
|
|
|
Potential
|
|
|
|
Net Physical
|
|
|
Gross Profit
|
|
|
(Loss)
|
|
|
Gross Profit
|
|
Period Ending
|
|
Position (Bcf)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
September 30, 2006
|
|
|
14.5
|
|
|
$
|
60.0
|
|
|
$
|
(16.0
|
)
|
|
$
|
76.0
|
|
September 30, 2005
|
|
|
6.9
|
|
|
$
|
13.1
|
|
|
$
|
(14.8
|
)
|
|
$
|
27.9
|
|
September 30, 2004
|
|
|
5.4
|
|
|
$
|
12.3
|
|
|
$
|
(0.8
|
)
|
|
$
|
13.1
|
|
As of September 30, 2006, based upon AEMs derivatives
position and inventory withdrawal schedule, the economic gross
profit was $60.0 million. In addition, $16.0 million
of net unrealized losses were recorded in the financial
statements as of September 30, 2006. Therefore, the
potential gross profit was $76.0 million. This potential
gross profit amount will not result in an equal increase in
future net income as AEM will incur additional storage and other
operational expenses to realize this amount.
The economic gross profit is based upon planned injection and
withdrawal schedules, and the realization of the economic gross
profit is contingent upon the execution of this plan, weather
and other execution factors. Since AEM actively manages and
optimizes its portfolio to enhance the future profitability of
its storage position, it may change its scheduled injection and
withdrawal plans from one time period to another based on market
conditions. Therefore, we cannot assure that the economic gross
profit or the potential gross profit calculated as of
September 30, 2006 will be fully realized in the future or
in what time period. Further, if we experience operational or
other issues which limit our ability to optimally manage our
stored gas positions, our earnings could be adversely impacted.
Pension
and Postretirement Benefits Obligations
Net
Periodic Pension and Postretirement Benefit Costs
For the fiscal year ended September 30, 2006, our total net
periodic pension and other benefits costs was
$50.0 million, compared with $36.4 million and
$26.1 million for the years ended September 30, 2005
and 2004. All of these costs are recoverable through our gas
utility rates; however, a portion of these costs is capitalized
into our utility rate base. The remaining costs are recorded as
a component of operation and maintenance expense.
The increase in total net periodic pension and other benefits
cost during fiscal 2006 compared with the prior year primarily
reflects changes in assumptions we made during our annual
pension plan valuation completed June 30, 2005. The
discount rate used to compute the present value of a plans
liabilities generally is based on rates of high-grade corporate
bonds with maturities similar to the average period over which
the benefits will be paid. In the period leading up to our
June 30, 2005 measurement date, these interest rates were
declining, which resulted in a 125 basis point reduction in
our discount rate to 5.0 percent. This reduction increased
the present value of our plan liabilities and associated
expenses. Additionally, we reduced the expected return on our
pension plan assets by 25 basis points to 8.5 percent,
which also increased our pension and postretirement benefit cost.
The increase in total net periodic pension and other benefits
cost during fiscal 2005 compared with fiscal 2004 primarily
reflects an increase in our service cost associated with the
increase in the number of employees
60
covered by our plans due to the TXU Gas acquisition. Although we
did not assume the existing employee benefit liabilities or
plans of TXU Gas, for purposes of determining our annual pension
cost we agreed to give the transitioned employees credit for
years of TXU Gas service under our pension plan. With respect to
our postretirement medical plan, we received a credit of
$18.9 million against the purchase price to permit us to
provide partial past service credits for retiree medical
benefits under our retiree medical plan. The $18.9 million
credit approximated the actuarially determined present value of
the accumulated benefits related to the past service of the
transferred employees on the acquisition date.
In addition to the increased number of employees covered by the
plans, we changed the assumptions used to determine our fiscal
2005 benefit costs, which resulted in an increase in our net
periodic pension and postretirement costs. We increased the
discount rate by 25 basis points and we reduced our
expected return on our pension plan assets by 25 basis
points. These assumption changes decreased the service cost and
interest cost and reduced the expected return components of our
pension and postretirement benefits costs.
Pension
and Postretirement Plan Funding
Generally, our funding policy is to contribute annually an
amount in accordance with the requirements of the Employee
Retirement Income Security Act of 1974. However, additional
voluntary contributions are made from time to time as considered
necessary. Contributions are intended to provide not only for
benefits attributed to service to date but also for those
expected to be earned in the future.
During fiscal 2006, we voluntarily contributed $2.9 million
to the Atmos Energy Corporation Retirement Plan for Mississippi
Valley Gas Union Employees. The current year contribution
achieved a desired level of funding by satisfying the minimum
funding requirements while maximizing the tax deductible
contribution for this plan for plan year 2005. During fiscal
2005, we voluntarily contributed $3.0 million to the Master
Trust to maintain the level of funding we desire relative to our
accumulated benefit obligation. We made the contribution because
declining high yield corporate bond yields in the period leading
up to our June 30, 2005 measurement date resulted in an
increase in the present value of our plan liabilities.
We contributed $10.9 million, $10.0 million and
$13.8 million to our postretirement benefits plans for the
years ended September 30, 2006, 2005 and 2004. The
contributions represent the portion of the postretirement costs
we are responsible for under the terms of our plan and minimum
funding required by our regulators.
Outlook
for Fiscal 2007
High grade corporate bond yields increased in the period leading
up to our June 30, 2006 measurement date. Therefore, we
increased the discount rate for determining our fiscal 2007
pension and benefit costs by 130 basis points to
6.3 percent. However, we reduced the expected return on our
pension plan assets by 25 basis points to
8.25 percent. The effect of these assumption changes,
coupled with the effects of updating our annual valuation should
not significantly affect our fiscal 2007 net pension and
postretirement costs compared to fiscal 2006.
We are not required to make a minimum funding contribution to
our pension plans during fiscal 2007; nor, at this time, do we
intend to make voluntary contributions during 2007. However, we
anticipate contributing approximately $11 million to our
postretirement medical plans during fiscal 2007.
The projected pension liability, future funding requirements and
the amount of pension expense or income recognized for the Plan
are subject to change, depending upon the actuarial value of
plan assets and the determination of future benefit obligations
as of each subsequent actuarial calculation date. These amounts
are impacted by actual investment returns, changes in interest
rates and changes in the demographic composition of the
participants in the plan.
61
RECENT
ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial
position, results of operations and cash flows are described in
Note 2 to the consolidated financial statements.
|
|
ITEM 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
We are exposed to risks associated with commodity prices and
interest rates. Commodity price risk is the potential loss that
we may incur as a result of changes in the fair value of a
particular instrument or commodity. Interest-rate risk results
from our portfolio of debt and equity instruments that we issue
to provide financing and liquidity for our business activities.
We conduct risk management activities through both our utility
and natural gas marketing segments. In our utility segment, we
use a combination of storage, fixed physical contracts and fixed
financial contracts to protect us and our customers against
unusually large winter period gas price increases. In our
natural gas marketing segment, we manage our exposure to the
risk of natural gas price changes and lock in our gross profit
margin through a combination of storage and financial
derivatives including futures,
over-the-counter
and exchange-traded options and swap contracts with
counterparties. Our risk management activities and related
accounting treatment are described in further detail in
Note 5 to the condensed consolidated financial statements.
Additionally, our earnings are affected by changes in short-term
interest rates as a result of our issuance of short-term
commercial paper, the issuance of floating rate debt in October
2004 and our other short-term borrowings.
Commodity
Price Risk
Utility
segment
We purchase natural gas for our utility operations.
Substantially all of the cost of gas purchased for utility
operations is recovered from our customers through purchased gas
adjustment mechanisms. However, our utility operations have
commodity price risk exposure to fluctuations in spot natural
gas prices related to purchases for sales to our non-regulated
energy services customers at fixed prices.
For our utility segment, we use a sensitivity analysis to
estimate commodity price risk. For purposes of this analysis, we
estimate commodity price risk by applying a hypothetical
10 percent increase in the portion of our gas cost related
to fixed-price non-regulated sales. Based on these projected
non-regulated gas sales, a hypothetical 10 percent increase
in fixed prices based upon the September 30, 2006 three
month market strip, would increase our purchased gas cost by
approximately $2.3 million in fiscal 2007.
Natural
gas marketing and pipeline and storage segments
Our natural gas marketing segment is also exposed to risks
associated with changes in the market price of natural gas. For
our natural gas marketing segment, we use a sensitivity analysis
to estimate commodity price risk. For purposes of this analysis,
we estimate commodity price risk by applying a $0.50 change in
the forward NYMEX price to our net open position (including
existing storage and related financial contracts) at the end of
each period. Based on AEHs net open position (including
existing storage and related financial contracts) at
September 30, 2006 of 0.2 Bcf, a $0.50 change in the
forward NYMEX price would have had less than a $0.1 million
impact on our consolidated net income.
Changes in the difference between the indices used to mark to
market our physical inventory (Gas Daily) and the related
fair-value hedge (NYMEX) can result in volatility in our
reported net income; but, over time, gains and losses on the
sale of storage gas inventory will be offset by gains and losses
on the fair-value hedges. Based upon our net physical position
at September 30, 2006 and assuming our hedges would still
qualify as highly effective, a $0.50 change in the difference
between the Gas Daily and NYMEX indices would impact our
reported net income by approximately $5.0 million.
62
Additionally, these changes could cause us to recognize a risk
management liability, which would require us to place cash into
an escrow account to collateralize this liability position.
This, in turn, would reduce the amount of cash we would have on
hand to fund our working capital needs. Because we recognized
risk management liabilities as of September 30, 2006, we
placed $35.6 million in escrow to collateralize these
liabilities.
Interest
Rate Risk
Our earnings are exposed to changes in short-term interest rates
associated with our short-term commercial paper program and
other short-term borrowings. We use a sensitivity analysis to
estimate our short-term interest rate risk. For purposes of this
analysis, we estimate our short-term interest rate risk as the
difference between our actual interest expense for the period
and estimated interest expense for the period assuming a
hypothetical average one percent increase in the interest rates
associated with our short-term borrowings. Had interest rates
associated with our short-term borrowings increased by an
average of one percent, our interest expense would have
increased by approximately $3.6 million during 2006.
We also assess market risk for our fixed and floating rate
long-term obligations. We estimate market risk for our long-term
obligations as the potential increase in fair value resulting
from a hypothetical one percent decrease in interest rates
associated with these debt instruments. Fair value is estimated
using a discounted cash flow analysis. Assuming this one percent
hypothetical decrease, the fair value of our long-term
obligations would have increased by approximately
$143.3 million.
As of September 30, 2006, we were not engaged in other
activities that would cause exposure to the risk of material
earnings or cash flow loss due to changes in interest rates or
market commodity prices.
63
|
|
ITEM 8.
|
Financial
Statements and Supplementary Data
|
Index to financial statements and financial statement schedule:
|
|
|
|
|
|
|
Page
|
|
|
|
|
65
|
|
Financial statements and
supplementary data:
|
|
|
|
|
|
|
|
66
|
|
|
|
|
67
|
|
|
|
|
68
|
|
|
|
|
69
|
|
|
|
|
70
|
|
|
|
|
123
|
|
|
|
|
|
|
Schedule II. Valuation and
Qualifying Accounts
|
|
|
131
|
|
All other financial statement schedules are omitted because the
required information is not present, or not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the financial statements and
accompanying notes thereto.
64
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
CONSOLIDATED FINANCIAL STATEMENTS
The Board of Directors
Atmos Energy Corporation
We have audited the accompanying consolidated balance sheets of
Atmos Energy Corporation as of September 30, 2006 and 2005,
and the related consolidated statements of income,
shareholders equity, and cash flows for each of the three
years in the period ended September 30, 2006. Our audits
also included the financial statement schedule listed in the
Index at Item 8. These financial statements and schedule
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Atmos Energy Corporation at
September 30, 2006 and 2005, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended September 30, 2006, in conformity with
U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the financial statements taken as a
whole, presents fairly, in all material respects, the financial
information set forth therein.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Atmos Energy Corporations internal
control over financial reporting as of September 30, 2006,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated
November 20, 2006 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Dallas, Texas
November 20, 2006
65
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands,
|
|
|
|
except share data)
|
|
|
ASSETS
|
Property, plant and equipment
|
|
$
|
5,026,478
|
|
|
$
|
4,631,684
|
|
Construction in progress
|
|
|
74,830
|
|
|
|
133,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,101,308
|
|
|
|
4,765,610
|
|
Less accumulated depreciation and
amortization
|
|
|
1,472,152
|
|
|
|
1,391,243
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
3,629,156
|
|
|
|
3,374,367
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
75,815
|
|
|
|
40,116
|
|
Cash held on deposit in margin
account
|
|
|
35,647
|
|
|
|
80,956
|
|
Accounts receivable, less
allowance for doubtful accounts of
$13,686 in 2006 and $15,613 in 2005
|
|
|
374,629
|
|
|
|
454,313
|
|
Gas stored underground
|
|
|
461,502
|
|
|
|
450,807
|
|
Other current assets
|
|
|
169,952
|
|
|
|
238,238
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,117,545
|
|
|
|
1,264,430
|
|
Goodwill and intangible assets
|
|
|
738,521
|
|
|
|
737,787
|
|
Deferred charges and other assets
|
|
|
234,325
|
|
|
|
276,943
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,719,547
|
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND
LIABILITIES
|
Shareholders equity
|
|
|
|
|
|
|
|
|
Common stock, no par value (stated
at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
|
|
|
|
|
|
|
|
|
2006
81,739,516 shares, 2005 80,539,401 shares
|
|
$
|
409
|
|
|
$
|
403
|
|
Additional paid-in capital
|
|
|
1,467,240
|
|
|
|
1,426,523
|
|
Accumulated other comprehensive
loss
|
|
|
(43,850
|
)
|
|
|
(3,341
|
)
|
Retained earnings
|
|
|
224,299
|
|
|
|
178,837
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
|
1,648,098
|
|
|
|
1,602,422
|
|
Long-term debt
|
|
|
2,180,362
|
|
|
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,828,460
|
|
|
|
3,785,526
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued
liabilities
|
|
|
345,108
|
|
|
|
461,314
|
|
Other current liabilities
|
|
|
388,451
|
|
|
|
503,368
|
|
Short-term debt
|
|
|
382,416
|
|
|
|
144,809
|
|
Current maturities of long-term
debt
|
|
|
3,186
|
|
|
|
3,264
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,119,161
|
|
|
|
1,112,755
|
|
Deferred income taxes
|
|
|
306,172
|
|
|
|
292,207
|
|
Regulatory cost of removal
obligation
|
|
|
261,376
|
|
|
|
263,424
|
|
Deferred credits and other
liabilities
|
|
|
204,378
|
|
|
|
199,615
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,719,547
|
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
66
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
$
|
3,650,591
|
|
|
$
|
3,103,140
|
|
|
$
|
1,637,728
|
|
Natural gas marketing segment
|
|
|
3,156,524
|
|
|
|
2,106,278
|
|
|
|
1,618,602
|
|
Pipeline and storage segment
|
|
|
160,567
|
|
|
|
153,289
|
|
|
|
19,758
|
|
Other nonutility segment
|
|
|
5,898
|
|
|
|
5,302
|
|
|
|
3,393
|
|
Intersegment eliminations
|
|
|
(821,217
|
)
|
|
|
(406,136
|
)
|
|
|
(359,444
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,152,363
|
|
|
|
4,961,873
|
|
|
|
2,920,037
|
|
Purchased gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
|
2,725,534
|
|
|
|
2,195,774
|
|
|
|
1,134,594
|
|
Natural gas marketing segment
|
|
|
3,025,897
|
|
|
|
2,044,305
|
|
|
|
1,571,971
|
|
Pipeline and storage segment
|
|
|
838
|
|
|
|
6,811
|
|
|
|
9,383
|
|
Other nonutility segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment eliminations
|
|
|
(816,476
|
)
|
|
|
(402,654
|
)
|
|
|
(358,102
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,935,793
|
|
|
|
3,844,236
|
|
|
|
2,357,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
1,216,570
|
|
|
|
1,117,637
|
|
|
|
562,191
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
433,418
|
|
|
|
416,281
|
|
|
|
214,470
|
|
Depreciation and amortization
|
|
|
185,596
|
|
|
|
178,005
|
|
|
|
96,647
|
|
Taxes, other than income
|
|
|
191,993
|
|
|
|
174,696
|
|
|
|
57,379
|
|
Impairment of long-lived assets
|
|
|
22,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
833,954
|
|
|
|
768,982
|
|
|
|
368,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
382,616
|
|
|
|
348,655
|
|
|
|
193,695
|
|
Miscellaneous income
|
|
|
881
|
|
|
|
2,021
|
|
|
|
9,507
|
|
Interest charges
|
|
|
146,607
|
|
|
|
132,658
|
|
|
|
65,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
236,890
|
|
|
|
218,018
|
|
|
|
137,765
|
|
Income tax expense
|
|
|
89,153
|
|
|
|
82,233
|
|
|
|
51,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share data
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per share
|
|
$
|
1.83
|
|
|
$
|
1.73
|
|
|
$
|
1.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per share
|
|
$
|
1.82
|
|
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
80,731
|
|
|
|
78,508
|
|
|
|
54,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
81,390
|
|
|
|
79,012
|
|
|
|
54,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
67
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Additional
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Stated
|
|
|
Paid-in
|
|
|
Comprehensive
|
|
|
Retained
|
|
|
|
|
|
|
Shares
|
|
|
Value
|
|
|
Capital
|
|
|
Loss
|
|
|
Earnings
|
|
|
Total
|
|
|
|
(In thousands, except share data)
|
|
|
Balance, September 30,
2003
|
|
|
51,475,785
|
|
|
$
|
257
|
|
|
$
|
736,180
|
|
|
$
|
(1,459
|
)
|
|
$
|
122,539
|
|
|
$
|
857,517
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,227
|
|
|
|
86,227
|
|
Unrealized holding gains on
investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
615
|
|
|
|
|
|
|
|
615
|
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,268
|
)
|
|
|
|
|
|
|
(21,268
|
)
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,583
|
|
|
|
|
|
|
|
7,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,157
|
|
Cash dividends ($1.22 per
share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(66,736
|
)
|
|
|
(66,736
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Public offering
|
|
|
9,939,393
|
|
|
|
50
|
|
|
|
235,419
|
|
|
|
|
|
|
|
|
|
|
|
235,469
|
|
Direct stock purchase plan
|
|
|
556,856
|
|
|
|
3
|
|
|
|
13,726
|
|
|
|
|
|
|
|
|
|
|
|
13,729
|
|
Retirement savings plan
|
|
|
320,313
|
|
|
|
2
|
|
|
|
8,300
|
|
|
|
|
|
|
|
|
|
|
|
8,302
|
|
1998 Long-term incentive plan
|
|
|
498,230
|
|
|
|
2
|
|
|
|
11,848
|
|
|
|
|
|
|
|
|
|
|
|
11,850
|
|
Long-term stock plan for Mid-States
Division
|
|
|
6,000
|
|
|
|
|
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
94
|
|
Outside directors
stock-for-fee
plan
|
|
|
3,133
|
|
|
|
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30,
2004
|
|
|
62,799,710
|
|
|
|
314
|
|
|
|
1,005,644
|
|
|
|
(14,529
|
)
|
|
|
142,030
|
|
|
|
1,133,459
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
135,785
|
|
|
|
135,785
|
|
Unrealized holding gains on
investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,528
|
|
|
|
|
|
|
|
1,528
|
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,714
|
)
|
|
|
|
|
|
|
(2,714
|
)
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,374
|
|
|
|
|
|
|
|
12,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
146,973
|
|
Cash dividends ($1.24 per
share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98,978
|
)
|
|
|
(98,978
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Public offering
|
|
|
16,100,000
|
|
|
|
80
|
|
|
|
381,271
|
|
|
|
|
|
|
|
|
|
|
|
381,351
|
|
Direct stock purchase plan
|
|
|
450,212
|
|
|
|
3
|
|
|
|
12,486
|
|
|
|
|
|
|
|
|
|
|
|
12,489
|
|
Retirement savings plan
|
|
|
441,350
|
|
|
|
2
|
|
|
|
11,767
|
|
|
|
|
|
|
|
|
|
|
|
11,769
|
|
1998 Long-term incentive plan
|
|
|
745,788
|
|
|
|
4
|
|
|
|
14,116
|
|
|
|
|
|
|
|
|
|
|
|
14,120
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
1,175
|
|
|
|
|
|
|
|
|
|
|
|
1,175
|
|
Outside directors
stock-for-fee
plan
|
|
|
2,341
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30,
2005
|
|
|
80,539,401
|
|
|
|
403
|
|
|
|
1,426,523
|
|
|
|
(3,341
|
)
|
|
|
178,837
|
|
|
|
1,602,422
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
147,737
|
|
|
|
147,737
|
|
Unrealized holding gains on
investments, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
882
|
|
|
|
|
|
|
|
882
|
|
Treasury lock agreements, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,442
|
|
|
|
|
|
|
|
3,442
|
|
Cash flow hedges, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,833
|
)
|
|
|
|
|
|
|
(44,833
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107,228
|
|
Cash dividends ($1.26 per
share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(102,275
|
)
|
|
|
(102,275
|
)
|
Common stock issued:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct stock purchase plan
|
|
|
387,833
|
|
|
|
2
|
|
|
|
10,391
|
|
|
|
|
|
|
|
|
|
|
|
10,393
|
|
Retirement savings plan
|
|
|
442,635
|
|
|
|
2
|
|
|
|
11,918
|
|
|
|
|
|
|
|
|
|
|
|
11,920
|
|
1998 Long-term incentive plan
|
|
|
366,905
|
|
|
|
2
|
|
|
|
8,976
|
|
|
|
|
|
|
|
|
|
|
|
8,978
|
|
Long-term stock plan for Mid-States
Division
|
|
|
300
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
9,361
|
|
|
|
|
|
|
|
|
|
|
|
9,361
|
|
Outside directors
stock-for-fee
plan
|
|
|
2,442
|
|
|
|
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30,
2006
|
|
|
81,739,516
|
|
|
$
|
409
|
|
|
$
|
1,467,240
|
|
|
$
|
(43,850
|
)
|
|
$
|
224,299
|
|
|
$
|
1,648,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
68
ATMOS
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
CASH FLOWS FROM OPERATING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
Adjustments to reconcile net
income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sales of assets
|
|
|
|
|
|
|
|
|
|
|
(6,700
|
)
|
Impairment of long-lived assets
|
|
|
22,947
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Charged to depreciation and
amortization
|
|
|
185,596
|
|
|
|
178,005
|
|
|
|
96,647
|
|
Charged to other accounts
|
|
|
371
|
|
|
|
791
|
|
|
|
1,465
|
|
Deferred income taxes
|
|
|
86,178
|
|
|
|
12,669
|
|
|
|
36,997
|
|
Other
|
|
|
18,480
|
|
|
|
11,522
|
|
|
|
(1,772
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in cash held
on deposit in margin account
|
|
|
45,309
|
|
|
|
(80,956
|
)
|
|
|
17,903
|
|
(Increase) decrease in accounts
receivable
|
|
|
78,407
|
|
|
|
(166,692
|
)
|
|
|
2,158
|
|
Increase in gas stored underground
|
|
|
(10,695
|
)
|
|
|
(112,796
|
)
|
|
|
(31,030
|
)
|
Increase in other current assets
|
|
|
(52,449
|
)
|
|
|
(56,828
|
)
|
|
|
(9,233
|
)
|
Decrease in deferred charges and
other assets
|
|
|
28,614
|
|
|
|
30,059
|
|
|
|
17,178
|
|
Increase (decrease) in accounts
payable and accrued liabilities
|
|
|
(116,060
|
)
|
|
|
224,375
|
|
|
|
4,586
|
|
Increase (decrease) in other
current liabilities
|
|
|
(113,977
|
)
|
|
|
218,715
|
|
|
|
48,877
|
|
Increase (decrease) in deferred
credits and other liabilities
|
|
|
(9,009
|
)
|
|
|
(7,705
|
)
|
|
|
7,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
311,449
|
|
|
|
386,944
|
|
|
|
270,734
|
|
CASH FLOWS USED IN INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(425,324
|
)
|
|
|
(333,183
|
)
|
|
|
(190,285
|
)
|
Acquisitions, net of cash received
|
|
|
|
|
|
|
(1,916,696
|
)
|
|
|
(1,957
|
)
|
Proceeds from sales of assets
|
|
|
|
|
|
|
|
|
|
|
27,919
|
|
Other, net
|
|
|
(5,767
|
)
|
|
|
(2,131
|
)
|
|
|
(570
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(431,091
|
)
|
|
|
(2,252,010
|
)
|
|
|
(164,893
|
)
|
CASH FLOWS FROM FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in
short-term debt
|
|
|
237,607
|
|
|
|
144,809
|
|
|
|
(118,595
|
)
|
Net proceeds from issuance of
long-term debt
|
|
|
|
|
|
|
1,385,847
|
|
|
|
5,000
|
|
Settlement of Treasury lock
agreements
|
|
|
|
|
|
|
(43,770
|
)
|
|
|
|
|
Repayment of long-term debt
|
|
|
(3,264
|
)
|
|
|
(103,425
|
)
|
|
|
(9,713
|
)
|
Cash dividends paid
|
|
|
(102,275
|
)
|
|
|
(98,978
|
)
|
|
|
(66,736
|
)
|
Issuance of common stock
|
|
|
23,273
|
|
|
|
37,183
|
|
|
|
34,715
|
|
Net proceeds from equity offering
|
|
|
|
|
|
|
381,584
|
|
|
|
235,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
155,341
|
|
|
|
1,703,250
|
|
|
|
80,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
and cash equivalents
|
|
|
35,699
|
|
|
|
(161,816
|
)
|
|
|
186,249
|
|
Cash and cash equivalents at
beginning of year
|
|
|
40,116
|
|
|
|
201,932
|
|
|
|
15,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of year
|
|
$
|
75,815
|
|
|
$
|
40,116
|
|
|
$
|
201,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
69
ATMOS
ENERGY CORPORATION
Atmos Energy Corporation (Atmos or the
Company) and its subsidiaries are engaged primarily in the
natural gas utility business as well as certain nonutility
businesses. Through our natural gas utility business, we
distribute natural gas through sales and transportation
arrangements to approximately 3.2 million residential,
commercial, public-authority and industrial customers through
our seven regulated natural gas utility divisions, in the
service areas described below:
|
|
|
Division
|
|
Service Area
|
|
Atmos Energy Colorado-Kansas
Division
|
|
Colorado, Kansas,
Missouri(2)
|
Atmos Energy Kentucky
Division(1)
|
|
Kentucky
|
Atmos Energy Louisiana Division
|
|
Louisiana
|
Atmos Energy Mid-States
Division(1)
|
|
Georgia(2),
Illinois(2),
Iowa(2),
Missouri(2),
Tennessee,
Virginia(2)
|
Atmos Energy Mid-Tex Division
|
|
Texas, including the
Dallas/Fort Worth metropolitan area
|
Atmos Energy Mississippi Division
|
|
Mississippi
|
Atmos Energy West Texas Division
|
|
West Texas
|
|
|
|
(1) |
|
Effective October 1, 2006, the Kentucky and Mid-States
Divisions were combined. |
|
(2) |
|
Denotes locations where we have more limited service areas. |
In addition, we transport natural gas for others through our
distribution system. Our utility business is subject to federal
and state regulation
and/or
regulation by local authorities in each of the states in which
the utility divisions operate. Our shared-services division is
located in Dallas, Texas, and our customer support centers are
located in Amarillo and Waco, Texas.
Our nonutility businesses operate in 22 states and include
our natural gas marketing operations, our pipeline and storage
operations and our other nonutility operations. These operations
are either organized under or managed by Atmos Energy Holdings,
Inc. (AEH), which is wholly-owned by the Company.
Our natural gas marketing operations are managed by Atmos Energy
Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides
a variety of natural gas management services to municipalities,
natural gas utility systems and industrial natural gas
customers, primarily in the southeastern and midwestern states
and to our Kentucky, Louisiana and Mid-States divisions. These
services consist primarily of furnishing natural gas supplies at
fixed and market-based prices, contract negotiation and
administration, load forecasting, gas storage acquisition and
management services, transportation services, peaking sales and
balancing services, capacity utilization strategies and gas
price hedging through the use of derivative instruments.
Our pipeline and storage operations consist of the operations of
our Atmos Pipeline Texas Division, a division of
Atmos Energy Corporation, and of Atmos Pipeline and Storage, LLC
(APS), which is wholly-owned by AEH. The Atmos
Pipeline Texas Division transports natural gas to
the Atmos Energy Mid-Tex Division, transports natural gas to
third parties and manages five underground storage reservoirs in
Texas. Through APS, we own or have 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.
70
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our other nonutility businesses consist primarily of the
operations of Atmos Energy Services (AES), LLC and Atmos Power
Systems, Inc., which are wholly-owned by AEH. 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. 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.
Prior to January 2004, United Cities Propane Gas, Inc., a
wholly-owned subsidiary of AEH, owned an approximate
19 percent membership interest in U.S. Propane L.P.
(USP), a joint venture formed in February 2000 with three other
utility companies. Through our ownership in USP, we owned an
approximate five percent indirect interest in Heritage Propane
Partners, L.P. (Heritage). During 2004, we sold our interest in
USP and Heritage. We received cash proceeds of
$26.6 million and recorded a pretax book gain of
$5.9 million with these transactions. We no longer have an
interest in the propane industry.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Principles of consolidation The accompanying
consolidated financial statements include the accounts of Atmos
Energy Corporation and its wholly-owned subsidiaries. All
material intercompany transactions have been eliminated.
Use of estimates The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses. The most significant
estimates include the allowance for doubtful accounts, legal and
environmental accruals, insurance accruals, pension and
postretirement obligations, deferred income taxes, asset
retirement obligation, impairment of long-lived assets, risk
management and trading activities and the valuation of goodwill,
indefinite-lived intangible assets and other long-lived assets.
Actual results could differ from those estimates.
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
accounting policies recognize the financial effects of the
ratemaking and accounting practices and policies of the various
regulatory commissions. Regulated utility operations are
accounted for in accordance with SFAS 71, Accounting for
the Effects of Certain Types of Regulation. This statement
requires cost-based, rate-regulated entities that meet certain
criteria to reflect the authorized recovery of costs due to
regulatory decisions in their financial statements. As a result,
certain costs are permitted to be capitalized rather than
expensed because they can be recovered through rates.
71
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We record regulatory assets as a component of other current
assets and deferred charges and other assets for costs that have
been deferred for which future recovery through customer rates
is considered probable. Regulatory liabilities are recorded
either on the face of the balance sheet or as a component of
current liabilities, deferred income taxes or deferred credits
and other liabilities when it is probable that revenues will be
reduced for amounts that will be credited to customers through
the ratemaking process. Significant regulatory assets and
liabilities as of September 30, 2006 and 2005 included the
following:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
|
Merger and integration costs, net
|
|
$
|
8,644
|
|
|
$
|
9,150
|
|
Deferred gas costs
|
|
|
44,992
|
|
|
|
38,173
|
|
Environmental costs
|
|
|
1,234
|
|
|
|
1,357
|
|
Rate case costs
|
|
|
10,579
|
|
|
|
11,314
|
|
Deferred franchise fees
|
|
|
1,311
|
|
|
|
6,710
|
|
Other
|
|
|
9,055
|
|
|
|
9,313
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
75,815
|
|
|
$
|
76,017
|
|
|
|
|
|
|
|
|
|
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
Deferred gas costs
|
|
$
|
68,959
|
|
|
$
|
134,048
|
|
Regulatory cost of removal
obligation
|
|
|
276,490
|
|
|
|
274,989
|
|
Deferred income taxes, net
|
|
|
235
|
|
|
|
3,185
|
|
Other
|
|
|
10,825
|
|
|
|
8,084
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
356,509
|
|
|
$
|
420,306
|
|
|
|
|
|
|
|
|
|
|
Currently authorized rates do not include a return on certain of
our merger and integration costs; however, we recover the
amortization of these costs. Merger and integration costs, net,
are generally amortized on a straight-line basis over estimated
useful lives ranging up to 20 years. During the fiscal
years ended September 30, 2006, 2005 and 2004, we
recognized $0.5 million, $2.3 million and
$8.2 million in amortization expense related to these
costs. Environmental costs have been deferred to be included in
future rate filings in accordance with rulings received from
various regulatory commissions.
As of September 30, 2006, our Mid-States Division had open
rate cases in its Missouri and Tennessee service areas seeking
rate increases of $3.4 million in each jurisdiction. The
Tennessee rate was settled in October 2006 and resulted in a
$6.1 million reduction in future annual revenues. We
anticipate that the Missouri rate case will be finalized in
February 2007. In addition, during 2006 our Mid-Tex Division
filed a system-wide case seeking incremental annual revenues of
approximately $60 million and several rate design changes.
A ruling on this filing is anticipated by April 2007.
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. Revenue is
recognized in our pipeline and storage segment as the services
are provided.
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
72
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 utilitys 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 utilitys other costs,
(ii) represents a large component of the utilitys
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. For the years ended
September 30, 2006, 2005 and 2004, we included unrealized
gains (losses) on open contracts of $17.2 million,
($26.0) million and ($2.8) million as a component of
natural gas marketing revenues.
Cash and cash equivalents We consider all
highly liquid investments with an initial or remaining maturity
of three months or less to be cash equivalents.
Cash held on deposit in margin account Cash
held on deposit in margin account consists of deposits made to
collateralize certain financial derivatives purchased in support
of our risk management activities. Under the terms of these
derivative contracts, when the fair value of financial
instruments held represents a net liability position, we are
required to deposit cash into a margin account.
Accounts receivable and allowance for doubtful
accounts Accounts receivable consist of natural
gas sales to residential, commercial, industrial, municipal,
agricultural and other customers. For the majority of our
receivables, we establish an allowance for doubtful accounts
based on our collections experience. On certain other
receivables where we are aware of a specific customers
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, customer deposits and general economic conditions.
Accounts are written off once they are deemed to be
uncollectible.
Gas stored underground Our gas stored
underground is comprised of natural gas injected into storage to
support the winter season withdrawals for our utility operations
and natural gas held by our natural gas marketing and other
nonutility subsidiaries to conduct their operations. The average
cost method is used for all our utility divisions, except for
certain jurisdictions in the Mid-States Division, where it is
valued on the
first-in
first-out method basis, in accordance with regulatory
requirements. The average gas cost method is also used for our
natural gas marketing segment and our Atmos Pipeline
Texas Division. Our Natural Gas Marketing segment utilizes the
average cost method; however, most of this inventory is hedged
and is therefore marked to market at the end of each month. Gas
in storage that is retained as cushion gas to maintain reservoir
pressure is classified as property, plant and equipment and is
valued at cost.
73
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Utility property, plant and equipment Utility
property, plant and equipment is stated at original cost, net of
contributions in aid of construction. The cost of additions
includes direct construction costs, payroll related costs
(taxes, pensions and other fringe benefits), administrative and
general costs and an allowance for funds used during
construction. The allowance for funds used during construction
represents the estimated cost of funds used to finance the
construction of major projects and are capitalized in the rate
base for ratemaking purposes when the completed projects are
placed in service. Interest expense of $3.6 million,
$2.5 million and $1.2 million was capitalized in 2006,
2005 and 2004.
Major renewals, including replacement pipe, and betterments that
are recoverable under our regulatory rate base are capitalized
while the costs of maintenance and repairs that are not
recoverable through rates are charged to expense as incurred.
The costs of large projects are accumulated in construction in
progress until the project is completed. When the project is
completed, tested and placed in service, the balance is
transferred to the utility plant in service account included in
the rate base and depreciation begins.
Utility property, plant and equipment is depreciated at various
rates on a straight-line basis over the estimated useful lives
of the assets. These rates are approved by our regulatory
commissions and are comprised of two components, one based on
average service life and one based on cost of removal.
Accordingly, we recognize our cost of removal expense as a
component of depreciation expense. The related cost of removal
accrual is reflected as a regulatory liability on the
consolidated balance sheet. At the time property, plant and
equipment is retired, removal expenses less salvage, are charged
to the regulatory cost of removal accrual. The composite
depreciation rate was 3.9 percent, 4.0 percent and
3.8 percent for the years ended September 30, 2006,
2005 and 2004.
Nonutility property, plant and equipment
Nonutility property, plant and equipment is stated at cost.
Depreciation is generally computed on the straight-line method
for financial reporting purposes based upon estimated useful
lives ranging from 8 to 38 years.
Asset retirement obligations SFAS 143,
Accounting for Asset Retirement Obligations and
FIN 47, Accounting for Conditional Asset Retirement
Obligations, which became effective for us
September 30, 2006, require that we record a liability at
fair value for an asset retirement obligation when the legal
obligation to retire the asset has been incurred with an
offsetting increase to the carrying value of the related asset.
Accretion of the asset retirement obligation due to the passage
of time is recorded as an operating expense.
As of September 30, 2006, we adopted the provisions of
FIN 47. As a result of adopting FIN 47, we recorded an
asset retirement obligation of $15.1 million associated
with our distribution system. As retirement costs incurred by
the distribution system are recovered from utility customers,
this liability had previously been captured in our regulatory
cost of removal liability. As a result of adopting FIN 47,
we reclassified the $15.1 million from regulatory cost of
removal liability to asset retirement obligation. In addition,
we recorded $4.8 million of asset retirement costs that
will be depreciated over the remaining life of the underlying
associated asset lives. We believe we have a legal obligation to
retire our storage wells. However, we have not recognized an
asset retirement obligation associated with our storage wells
because there is not sufficient industry history to reasonably
estimate the fair value of this obligation. The adoption of
FIN 47 did not have an impact to our results operations as
the cost of removal expense has previously been recorded as
described above. In accordance with the transition guidance of
FIN 47, prior periods have not been restated; however, the
asset retirement obligation as of September 30, 2005 would
have been $14.6 million.
Impairment of long-lived assets We
periodically evaluate whether events or circumstances have
occurred that indicate that other long-lived assets may not be
recoverable or that the remaining useful life may warrant
revision. When such events or circumstances are present, we
assess the recoverability of long-lived assets by determining
whether the carrying value will be recovered through the
expected future cash flows. In the event the sum of the expected
future cash flows resulting from the use of the asset is less
than the carrying
74
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
value of the asset, an impairment loss equal to the excess of
the assets carrying value over its fair value is recorded.
During the fourth quarter of fiscal 2006, 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 Divisions irrigation assets
would not be able to generate sufficient future cash flows from
operations to recover the net investment in these assets.
Therefore, we recorded a $22.9 million charge to impairment
to write off the entire net book value. 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.
Goodwill and intangible assets We annually
evaluate our goodwill balances for impairment during our second
fiscal quarter or more frequently as impairment indicators
arise. We use a present value technique based on discounted cash
flows to estimate the fair value of our reporting units. These
calculations are dependent on several subjective factors
including the timing of future cash flows, future growth rates
and the discount rate. An impairment charge is recognized if the
carrying value of a reporting units goodwill exceeds its
fair value.
Intangible assets are amortized over their useful lives of
10 years. These assets are reviewed for impairment as
impairment indicators arise. When such events or circumstances
are present, we assess the recoverability of long-lived assets
by determining whether the carrying value will be recovered
through the expected future cash flows. In the event the sum of
the expected future cash flows resulting from the use of the
asset is less than the carrying value of the asset, an
impairment loss equal to the excess of the assets carrying
value over its fair value is recorded. To date, no impairment
has been recognized.
Marketable securities As of
September 30, 2006 and 2005, all of our marketable
securities were classified as
available-for-sale
securities based upon the criteria of SFAS 115,
Accounting for Certain Investments in Debt and Equity
Securities. In accordance with that standard, these
securities are reported at market value with unrealized gains
and losses shown as a component of accumulated other
comprehensive income (loss). We regularly evaluate the
performance of these investments on a fund by fund basis for
impairment, taking into consideration the funds purpose,
volatility and current returns. If a determination is made that
a decline in fair value is other than temporary, the related
fund is written down to its estimated fair value.
Derivatives and hedging activities Our
derivative and hedging activities are tailored to the segment to
which they relate. We record our derivatives as a component of
risk management assets and liabilities, which are classified as
current or noncurrent other assets or liabilities based upon the
anticipated settlement date of the underlying derivative. Our
determination of the fair value of these derivative financial
instruments reflects the estimated amounts that we would receive
or pay to terminate or close the contracts at the reporting
date, taking into account the current unrealized gains and
losses on open contracts. In our determination of fair value, we
consider various factors, including closing exchange and
over-the-counter
quotations, time value and volatility factors underlying the
contracts. Effective October 1, 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 did not have a material impact on our financial
position on the date of adoption.
Utility
Segment
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 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, maturity and settlement
75
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of contracts and newly originated transactions. However, because
the gains or losses 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 gain
or loss is recovered through our rates.
Natural
Gas Marketing Segment
Our natural gas marketing risk management activities are
conducted through AEM. AEM is exposed to risks associated with
changes in the market price of natural gas, and we manage our
exposure to the risk of natural gas price changes 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 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 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.
Under SFAS 133, natural gas inventory is designated as the
hedged item in a fair-value hedge and is marked to market at the
end of each month with changes in fair value recognized as
unrealized gains and losses in revenue in the period of change.
Effective October 1, 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 and 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 hedge (NYMEX) is reported as a component of revenue
and can result in volatility in our reported net income. Over
time, gains and losses on the sale of storage gas inventory will
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. In addition, we continually manage our positions to
optimize value as market conditions and other circumstances
change. When evaluating effectiveness, we 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.
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 1, 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
76
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 were settled. To the extent that
the 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
have 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
are now 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. In
addition, we continually manage our positions to optimize value
as market conditions and other circumstances change.
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 of our
natural gas marketing segment.
In our natural gas marketing segment, hedge ineffectiveness
arising from natural gas market price differences between the
locations of the hedged inventory and the delivery location
specified in the hedge instruments (referred to as basis
ineffectiveness) for our fair value hedges resulted in an
unrealized gain of $15.5 million for the year ended
September 30, 2006 compared with an unrealized loss of
$1.7 million and $0.6 million for the years ended
September 30, 2005 and 2004. Basis ineffectiveness for our
cash flow hedges resulted in an unrealized gain of approximately
$20.0 million for the year ended September 30, 2006
compared with an unrealized loss of approximately
$3.7 million and $0.5 million for the years ended
September 30, 2005 and 2004. Hedge ineffectiveness arising
from the timing of the settlement of physical contracts and the
settlement of the related fair value hedge resulted in an
unrealized gain of approximately $4.4 million and
$0.5 million for the years ended September 30, 2006
and 2004 and an unrealized loss of approximately
$2.2 million for the year ended September 30, 2005.
The increased ineffectiveness is due to the high level of market
volatility experienced in 2006.
Additionally, we have a policy which allows for the use of
master netting agreements with significant counterparties that
allow us to offset gains and losses arising from derivative
instruments that may be settled in cash and/or gains and losses
arising from derivative instruments that may be settled with the
physical commodity. Assets and liabilities from risk management
activities, as well as accounts receivable and payable, reflect
the master netting agreements in place.
Pipeline
and Storage Segment
Similar to AEM, Atmos Pipeline and Storage, LLC has designated
its natural gas inventory as the hedged item in a fair-value
hedge. The inventory is marked to market at the end of each
month based upon Gas Daily index. 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.
77
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 and 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 hedge (NYMEX) is reported as a component of revenue
and can result in volatility in our reported net income. Over
time, gains and losses on the sale of natural gas inventory
should 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.
In our pipeline and storage segment, actual hedge
ineffectiveness arising from the timing of settlement of
physical contracts and the settlement of the derivative
instruments resulted in a loss of approximately
$4.7 million for the year ended September 30, 2006, a
gain of approximately $5.2 million for the year ended
September 30, 2005 and a loss of less than
$0.1 million for the year ended September 30, 2004.
Treasury
Activities
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, to the extent effective, unrealized
gains and losses associated with the Treasury lock agreements
are 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. Approximately $11.6 million of the
$43.8 million obligation is being recognized as a component
of interest expense over a five year period from the date of
settlement, and the remaining amount, approximately
$32.2 million, is being recognized as a component of
interest expense over a ten year period from the date of
settlement.
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 present market conditions.
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 Moodys 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.
78
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The expected long-term rate of return on assets is utilized in
calculating the expected return on plan assets component of the
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 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 years 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 cost 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.
Income taxes Income taxes are provided based
on the liability method, which results in income tax assets and
liabilities arising from temporary differences. Temporary
differences are differences between the tax bases of assets and
liabilities and their reported amounts in the financial
statements that will result in taxable or deductible amounts in
future years. The liability method requires the effect of tax
rate changes on current and accumulated deferred income taxes to
be reflected in the period in which the rate change was enacted.
The liability method also requires that deferred tax assets be
reduced by a valuation allowance unless it is more likely than
not that the assets will be realized.
Stock-based compensation plans We maintain
the 1998 Long-Term Incentive Plan that provides for the granting
of incentive stock options, non-qualified stock options, stock
appreciation rights, bonus stock, time-lapse restricted stock,
performance-based restricted stock units and stock units to
officers, division presidents and other key employees.
Non-employee directors are also eligible to receive stock-based
compensation under the 1998 Long-Term Incentive Plan. The
objectives of this plan include attracting and retaining the
best personnel, providing for additional performance incentives
and promoting our success by providing employees with the
opportunity to acquire our common stock.
On October 1, 2005, the Company adopted SFAS 123
(revised), Share-Based Payment (SFAS 123(R)). This
standard revises SFAS 123, Accounting for Stock-Based
Compensation and supersedes Accounting Principles Board
(APB) Opinion 25, Accounting for Stock Issued to
Employees. Under SFAS 123(R), the Company is required
to measure the cost of employee services received in exchange
for stock options and similar awards based on the grant-date
fair value of the award and recognize this cost in the income
statement over the period during which an employee is required
to provide service in exchange for the award.
We adopted SFAS 123(R) using the modified prospective
method. Under this transition method, stock-based compensation
expense for the year ended September 30, 2006 included:
(i) compensation expense for all stock-based compensation
awards granted prior to, but not yet vested as of
October 1, 2005, based on the grant-date fair value
estimated in accordance with the original provisions of
SFAS 123; and (ii) compensation expense for all
stock-based compensation awards granted subsequent to
October 1, 2005, based on the grant-date fair value
estimated in accordance with the provisions of SFAS 123(R).
We recognize compensation expense on a straight-line basis over
the requisite service period of the award. The impact of
adoption on total stock-based compensation expense included in
our statement of income for the year ended September 30,
2006 was $0.4 million and was recorded as a component of
operation and maintenance expense. In accordance with the
modified prospective method, financial results for prior periods
have not been restated.
Prior to October 1, 2005, we accounted for these plans
under the intrinsic-value method described in
APB Opinion 25, as permitted by SFAS 123. Under
this method, no compensation cost for stock options was
recognized for stock-option awards granted at or above
fair-market value. Awards of restricted stock were
79
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
valued at the market price of the Companys common stock on
the date of grant. The unearned compensation was amortized as a
component of operation and maintenance expense over the vesting
period of the restricted stock.
Total stock-based compensation expense for the year ended
September 30, 2006 was $9.4 million as compared to
$3.9 million and $1.6 million for the years ended
September 30, 2005 and 2004. Had compensation expense for
our stock-based awards been recognized as prescribed by
SFAS 123, our net income and earnings per share for the
years ended September 30, 2005 and 2004 would have been
impacted as shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income as reported
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
Restricted stock compensation
expense included in income, net of tax
|
|
|
2,431
|
|
|
|
978
|
|
Total stock-based employee
compensation expense determined under
fair-value-
based method for all awards, net of taxes
|
|
|
(3,161
|
)
|
|
|
(2,092
|
)
|
|
|
|
|
|
|
|
|
|
Net income pro forma
|
|
$
|
135,055
|
|
|
$
|
85,113
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
Basic earnings per
share as reported
|
|
$
|
1.73
|
|
|
$
|
1.60
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per
share pro forma
|
|
$
|
1.72
|
|
|
$
|
1.57
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per
share as reported
|
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per
share pro forma
|
|
$
|
1.71
|
|
|
$
|
1.56
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss
Accumulated other comprehensive loss, net of tax, as of
September 30, 2006 and 2005 consisted of the following
unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Unrealized holding gains on
investments
|
|
$
|
1,566
|
|
|
$
|
684
|
|
Treasury lock agreements
|
|
|
(20,540
|
)
|
|
|
(23,982
|
)
|
Cash flow hedges
|
|
|
(24,876
|
)
|
|
|
19,957
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(43,850
|
)
|
|
$
|
(3,341
|
)
|
|
|
|
|
|
|
|
|
|
Recent accounting pronouncements In February
2006, the FASB issued SFAS 155, Accounting for Certain
Hybrid Financial Instruments, which amends SFAS 133,
Accounting for Derivative Instruments and Hedging Activities
and SFAS 140, Accounting for Transfers and Servicing
of Financial Assets and Extinguishments of Liabilities.
SFAS 155 (a) permits fair value remeasurement for any
hybrid financial instrument that contains an embedded derivative
that otherwise would require bifurcation, (b) clarifies
which interest-only strips and principal-only strips are not
subject to the requirements of SFAS 133,
(c) establishes a requirement to evaluate interests in
securitized financial assets to identify interests that are
freestanding derivatives or that are hybrid financial
instruments that contain an embedded derivative requiring
bifurcation, (d) clarifies that concentrations of credit
risk in the form of subordination are not embedded derivatives
and (e) amends SFAS 140 to eliminate the prohibition
on a qualifying special-purpose entity from holding a derivative
financial instrument that pertains to a beneficial interest
other than another derivative financial instrument.
SFAS 155 is effective for
80
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
all financial instruments acquired or issued by us after
October 1, 2006 and the adoption of this standard is not
expected to have a material impact on our financial position,
results of operations and cash flows.
In March 2006, the FASB issued SFAS 156, Accounting for
Servicing Financial Assets, which amends SFAS 140,
Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities. SFAS 156
(a) revises guidance on when a servicing asset and
servicing liability should be recognized, (b) requires all
separately recognized servicing assets and servicing liabilities
to be initially measured at fair value, if practicable,
(c) permits an entity to choose to measure servicing assets
and servicing liabilities under the amortization method or fair
value measurement method, (d) at initial adoption, permits
a one-time reclassification of
available-for-sale
securities to trading securities by entities with recognized
servicing rights, without calling into question the treatment of
other
available-for-sale
securities under SFAS 115, provided that the
available-for-sale
securities are identified as offsetting the exposure to changes
in the fair value of servicing assets or liabilities that the
servicer elects to subsequently measure at fair value and
(e) requires separate presentation of servicing assets and
servicing liabilities subsequently measured at fair value in the
statement of financial position and additional footnote
disclosure. We will be required to apply the provisions of
SFAS 156 beginning October 1, 2006 and such
application is expected not to have a material impact on our
financial position, results of operations and cash flows.
In June 2006, the Emerging Issues Task Force (EITF) ratified
EITF Issue
No. 06-3,
How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income
Statement (That Is, Gross versus Net Presentation). The EITF
reached a consensus that the scope of this issue includes any
tax assessed by a governmental authority that is directly
imposed on a revenue-producing transaction between a seller and
a customer and may include sales, use, value added and some
excise taxes. The EITF also reached a consensus that entities
may present these taxes on either a gross or net basis. If the
taxes are significant, an entity should disclose its policy of
presenting taxes and the amounts of taxes that are recognized on
a gross basis in interim and annual financial statements. We
will be required to apply the provisions of
EITF 06-3
beginning January 1, 2007. We are currently evaluating the
impact this standard may have on our results of operations.
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation
of FASB Statement No. 109 (FIN 48). FIN 48
clarifies the accounting for uncertainty in income taxes by
establishing standards for measurement and recognition in
financial statements of positions taken by an entity in its
income tax returns. This interpretation also provides guidance
on de-recognition of income tax assets and liabilities,
classification of current and deferred income tax assets and
liabilities, accounting for interest and penalties, accounting
for income taxes in interim periods and income tax disclosures.
We will be required to apply the provisions of FIN 48
beginning October 1, 2007. We are currently evaluating the
impact this standard may have on our financial position, results
of operations and cash flows.
In September 2006, the FASB issued SFAS 157, Fair Value
Measurements. SFAS 157 defines fair value, establishes
a framework for measuring fair value and enhances disclosures
about fair value measurements required under other accounting
pronouncements but does not change existing guidance as to
whether or not an instrument is carried at fair value. We will
be required to apply the provisions of SFAS 157 beginning
October 1, 2008. We are currently evaluating the impact
this standard may have on our financial position, results of
operations and cash flows.
In September 2006, the FASB issued SFAS 158,
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R). The new standard makes a
significant change to the existing rules by requiring
recognition in the balance sheet of the overfunded or
underfunded positions of defined benefit pension and other
postretirement plans, along with a corresponding noncash,
after-tax adjustment to stockholders equity. Additionally,
this standard requires that the measurement date must correspond
to the fiscal year end balance sheet date. This standard does
not change how net periodic pension and postretirement cost or
the projected benefit obligation is determined. The balance
sheet recognition
81
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
guidance of this standard will be effective for fiscal 2007 and
the measurement date provisions of this guidance can be adopted
as late as fiscal 2008 for our company.
TXU
Gas Company
In October 2004, we completed our acquisition of the natural gas
distribution and pipeline operations of TXU Gas Company. The
purchase price for the TXU Gas acquisition was approximately
$1.9 billion (after closing adjustments and before
transaction costs and expenses), which we paid in cash. We did
not assume any indebtedness of TXU Gas in connection with the
acquisition. The purchase was accounted for as an asset
purchase. We funded the purchase price for the TXU Gas
acquisition with approximately $235.7 million in net
proceeds from our offering of approximately 9.9 million
shares of common stock, which we completed in July 2004, and
approximately $1.7 billion in net proceeds from our
issuance in October 2004 of commercial paper backstopped by a
senior unsecured revolving credit agreement, which we entered
into in September 2004 to provide bridge financing for the TXU
Gas acquisition. In October 2004, we paid off the outstanding
commercial paper used to fund the acquisition through the
issuance of senior unsecured notes in October 2004, which
generated net proceeds of approximately $1.39 billion, and
the sale of 16.1 million shares of common stock in October
2004, which generated net proceeds of $381.6 million.
The following table summarizes the fair values of the assets
acquired and liabilities assumed on October 1, 2004 (in
thousands):
|
|
|
|
|
Cash purchase price
|
|
$
|
1,908,999
|
|
Transaction costs and expenses
|
|
|
7,697
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
1,916,696
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
1,471,643
|
|
Accounts receivable
|
|
|
75,811
|
|
Gas stored underground
|
|
|
137,877
|
|
Other current assets
|
|
|
22,094
|
|
Goodwill
|
|
|
493,603
|
|
Deferred charges and other assets
|
|
|
42,069
|
|
Deferred income taxes
|
|
|
7,925
|
|
Accounts payable and accrued
liabilities
|
|
|
(51,644
|
)
|
Other current liabilities
|
|
|
(77,756
|
)
|
Regulatory cost of removal
obligation
|
|
|
(138,991
|
)
|
Deferred credits and other
liabilities
|
|
|
(65,935
|
)
|
|
|
|
|
|
Total
|
|
$
|
1,916,696
|
|
|
|
|
|
|
The sale of the TXU Gas operations was held through a
competitive bid process. We believe the resulting goodwill is
recoverable given the expected synergies we can achieve as a
result of the TXU Gas acquisition. To that end, the TXU Gas
acquisition significantly expands our existing utility
operations in Texas. The North Texas operations of TXU Gas
bridge our geographic operations between our existing utility
operations in West Texas and Louisiana. TXU Gass
headquarters and service area are centered in Dallas, Texas,
which is also the location of our corporate headquarters.
Further, the addition of the regulated pipelines and storage
operations in North Texas may create additional gas marketing
and other opportunities for our non-regulated subsidiaries,
which include gas marketing and storage operations. The goodwill
generated in the acquisition is deductible for tax purposes.
At closing of the acquisition, TXU Gas and some of its
affiliates entered into transitional services agreements with us
to provide call center, meter reading, customer billing,
collections, information reporting,
82
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
software, accounting, treasury, administrative and other
services to the Mid-Tex Division. Some of these services were
outsourced by TXU Gas to Capgemini Energy L.P. However, in
November 2004, we entered into an agreement with Capgemini
Energy L.P. whereby we assumed the operations of the Waco, Texas
call center in April 2005 and purchased from Capgemini Energy
L.P. all of the related call center assets in October 2005. The
remaining transitional services agreements expired in September
2005 and were not renewed as we in-sourced all of these
functions, effective October 2005.
The table below reflects the unaudited pro forma results of the
Company and TXU Gas for the year ended September 30, 2004
as if the acquisition and related financing had taken place at
the beginning of fiscal 2004 (in thousands, except per share
data):
|
|
|
|
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
|
2004
|
|
|
Operating revenue
|
|
$
|
4,174,500
|
|
Net income
|
|
|
118,746
|
|
Net income per diluted share
|
|
$
|
1.68
|
|
ComFurT
Gas Inc.
Effective March 2004, we completed the acquisition of the
natural gas distribution assets of ComFurT Gas Inc., a
privately-held natural gas utility and propane distributor based
in Buena Vista, Colorado, for approximately $2.0 million in
cash. This company served approximately 1,800 natural gas
utility customers. The acquisition enabled us to expand our
contiguous service area in our Colorado-Kansas division.
Unaudited pro forma results of the Company and ComFurT have not
been presented as the acquisition was not material to our
financial position or results of operations.
|
|
4.
|
Goodwill
and Intangible Assets
|
Goodwill and intangible assets were comprised of the following
as of September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Goodwill
|
|
$
|
735,369
|
|
|
$
|
734,280
|
|
Intangible assets
|
|
|
3,152
|
|
|
|
3,507
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
738,521
|
|
|
$
|
737,787
|
|
|
|
|
|
|
|
|
|
|
The following presents our goodwill balance allocated by segment
and changes in the balance for the year ended September 30,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline and
|
|
|
Other
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
|
|
|
|
Segment
|
|
|
Segment
|
|
|
Segment
|
|
|
Segment
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance as of September 30,
2005
|
|
$
|
566,800
|
|
|
$
|
24,282
|
|
|
$
|
143,198
|
|
|
$
|
|
|
|
$
|
734,280
|
|
Deferred tax adjustments on prior
acquisitions(1)
|
|
|
421
|
|
|
|
|
|
|
|
668
|
|
|
|
|
|
|
|
1,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30,
2006
|
|
$
|
567,221
|
|
|
$
|
24,282
|
|
|
$
|
143,866
|
|
|
$
|
|
|
|
$
|
735,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the preparation of the fiscal 2006 tax provision, we
adjusted certain deferred taxes recorded in connection with a
fiscal 2001 and a fiscal 2004 acquisitions which resulted in an
increase to goodwill and net deferred tax liabilities of
$1.1 million. |
83
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Information regarding our intangible assets is included in the
following table. As of September 30, 2006 and 2005, we had
no indefinite-lived intangible assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006
|
|
|
September 30, 2005
|
|
|
|
Useful
|
|
|
Gross
|
|
|
|
|
|
|
|
|
Gross
|
|
|
|
|
|
|
|
|
|
Life
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
|
|
|
|
(Years)
|
|
|
Amount
|
|
|
Amortization
|
|
|
Net
|
|
|
Amount
|
|
|
Amortization
|
|
|
Net
|
|
|
|
(In thousands)
|
|
|
Customer contracts
|
|
|
10
|
|
|
$
|
6,754
|
|
|
$
|
(3,602
|
)
|
|
$
|
3,152
|
|
|
$
|
6,521
|
|
|
$
|
(3,014
|
)
|
|
$
|
3,507
|
|
The following table presents actual amortization expense
recognized during 2006 and an estimate of future amortization
expense based upon our intangible assets at September 30,
2006.
|
|
|
|
|
Amortization expense (in
thousands):
|
|
|
|
|
Actual for the fiscal year ending
September 30, 2006
|
|
$
|
588
|
|
Estimated for the fiscal year
ending:
|
|
|
|
|
September 30, 2007
|
|
|
608
|
|
September 30, 2008
|
|
|
608
|
|
September 30, 2009
|
|
|
608
|
|
September 30, 2010
|
|
|
608
|
|
September 30, 2011
|
|
|
608
|
|
|
|
5.
|
Derivative
Instruments and Hedging Activities
|
We conduct risk management activities through both our utility
and natural gas marketing segments. These activities are
described in more detail in Note 2. Also, as discussed in
Note 2, we record our derivatives as a component of risk
management assets and liabilities, which are classified as
current or noncurrent based upon the anticipated settlement date
of the underlying derivative. Our determination of the fair
value of these derivative financial instruments reflects the
estimated amounts that we would receive or pay to terminate or
close the contracts at the reporting date, taking into account
the current unrealized gains and losses on open contracts. In
our determination of fair value, we consider various factors,
including closing exchange and
over-the-counter
quotations, time value and volatility factors underlying the
contracts. These risk management assets and liabilities are
subject to continuing market risk until the underlying
derivative contracts are settled.
84
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table shows the fair values of our risk management
assets and liabilities by segment at September 30, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
September 30,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management
activities, current
|
|
$
|
|
|
|
$
|
12,553
|
|
|
$
|
12,553
|
|
Assets from risk management
activities, noncurrent
|
|
|
|
|
|
|
6,186
|
|
|
|
6,186
|
|
Liabilities from risk management
activities, current
|
|
|
(27,209
|
)
|
|
|
(3,460
|
)
|
|
|
(30,669
|
)
|
Liabilities from risk management
activities, noncurrent
|
|
|
|
|
|
|
(276
|
)
|
|
|
(276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
(27,209
|
)
|
|
$
|
15,003
|
|
|
$
|
(12,206
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets from risk management
activities, current
|
|
$
|
93,310
|
|
|
$
|
14,603
|
|
|
$
|
107,913
|
|
Assets from risk management
activities, noncurrent
|
|
|
|
|
|
|
735
|
|
|
|
735
|
|
Liabilities from risk management
activities, current
|
|
|
|
|
|
|
(61,920
|
)
|
|
|
(61,920
|
)
|
Liabilities from risk management
activities, noncurrent
|
|
|
|
|
|
|
(15,316
|
)
|
|
|
(15,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets (liabilities)
|
|
$
|
93,310
|
|
|
$
|
(61,898
|
)
|
|
$
|
31,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Hedging Activities
We use a combination of storage, fixed physical contracts and
fixed financial contracts to partially insulate us and our
customers against gas price volatility during the winter heating
season. For the
2005-2006
heating season, we hedged approximately 46 percent of our
anticipated winter flowing gas requirements at a weighted
average cost of approximately $9.06 per Mcf.
Our utility hedging activities also includes the fair value of
our treasury lock agreements which are described in further
detail below.
Nonutility
Hedging Activities
For the year ended September 30, 2006, the change in the
deferred hedging position in accumulated other comprehensive
loss was attributable to decreases in future commodity prices
relative to the commodity prices stipulated in the derivative
contracts totaling $51.0 million and the recognition of
$6.2 million in net deferred hedging losses in net income
when the derivatives matured according to their terms. The net
deferred hedging losses associated with open cash flow hedges
remain subject to market price fluctuations until the positions
are either settled under the terms of the hedge contracts or
terminated prior to settlement. Substantially all of the
deferred hedging loss as of September 30, 2006 is expected
to be recognized in net income within the next fiscal year.
Under our risk management policies, we seek to match our
financial derivative positions to our physical storage positions
as well as our expected current and future sales and purchase
obligations to maintain no open positions at the end of each
trading day. The determination of our net open position as of
any day, however, 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. We can also be affected by intraday
fluctuations of gas prices, since the price of natural gas
purchased or sold for future delivery earlier in the day may not
be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur.
85
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At the close of business on September 30, 2006, AEH had a
net open position (including existing storage) of 0.2 Bcf.
Treasury
Activities
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-then anticipated issuance
of $875 million of long-term debt subsequent to
September 30, 2004. This long-term debt was issued in
October 2004 and was used to repay a portion of the commercial
paper used to fund the TXU Gas acquisition, as described in
Note 3.
We designated these Treasury lock agreements as cash flow hedges
of an anticipated transaction. Accordingly, to the extent
effective, unrealized gains and losses associated with the
Treasury locks were recorded as a component of accumulated other
comprehensive loss. These Treasury lock agreements were settled
in October 2004 with a net $43.8 million payment to the
counterparties. Approximately $11.6 million of the
$43.8 million obligation is being recognized as a component
of interest expense over a five year period from the date of
settlement, and the remaining amount, approximately
$32.2 million, is being recognized as a component of
interest expense over a ten year period from the date of
settlement.
The following table presents our hedging transactions that were
recorded to other comprehensive income (loss), net of taxes
during the years ended September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Increase (decrease) in fair
value:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
$
|
|
|
|
$
|
(5,869
|
)
|
Forward commodity contracts
|
|
|
(51,014
|
)
|
|
|
1,988
|
|
Recognition of (gains) losses
in earnings due to settlements:
|
|
|
|
|
|
|
|
|
Treasury lock agreements
|
|
|
3,442
|
|
|
|
3,155
|
|
Forward commodity contracts
|
|
|
6,181
|
|
|
|
10,386
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income
(loss) from hedging, net of
tax(1)
|
|
$
|
(41,391
|
)
|
|
$
|
9,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Utilizing an income tax rate of approximately 38 percent
comprised of the effective rates in each taxing jurisdiction. |
The following amounts, net of deferred taxes, represent the
expected recognition into earnings for our derivative
instruments, based upon the fair values of these derivatives as
of September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury
|
|
|
|
|
|
|
|
|
|
Lock
|
|
|
Forward
|
|
|
|
|
|
|
Agreements
|
|
|
Contracts
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2007
|
|
$
|
(3,442
|
)
|
|
$
|
(24,100
|
)
|
|
$
|
(27,542
|
)
|
2008
|
|
|
(3,442
|
)
|
|
|
(732
|
)
|
|
|
(4,174
|
)
|
2009
|
|
|
(3,442
|
)
|
|
|
(38
|
)
|
|
|
(3,480
|
)
|
2010
|
|
|
(2,123
|
)
|
|
|
(6
|
)
|
|
|
(2,129
|
)
|
2011
|
|
|
(2,003
|
)
|
|
|
|
|
|
|
(2,003
|
)
|
Thereafter
|
|
|
(6,088
|
)
|
|
|
|
|
|
|
(6,088
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(20,540
|
)
|
|
$
|
(24,876
|
)
|
|
$
|
(45,416
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-term
debt
Long-term debt at September 30, 2006 and 2005 consisted of
the following:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Unsecured floating rate Senior
Notes, due October 2007
|
|
$
|
300,000
|
|
|
$
|
300,000
|
|
Unsecured 4.00% Senior Notes,
due 2009
|
|
|
400,000
|
|
|
|
400,000
|
|
Unsecured 7.375% Senior
Notes, due 2011
|
|
|
350,000
|
|
|
|
350,000
|
|
Unsecured 10% Notes, due 2011
|
|
|
2,303
|
|
|
|
2,303
|
|
Unsecured 5.125% Senior
Notes, due 2013
|
|
|
250,000
|
|
|
|
250,000
|
|
Unsecured 4.95% Senior Notes,
due 2014
|
|
|
500,000
|
|
|
|
500,000
|
|
Unsecured 5.95% Senior Notes,
due 2034
|
|
|
200,000
|
|
|
|
200,000
|
|
Medium term notes
|
|
|
|
|
|
|
|
|
Series A, 1995-2, 6.27%, due
2010
|
|
|
10,000
|
|
|
|
10,000
|
|
Series A, 1995-1, 6.67%, due
2025
|
|
|
10,000
|
|
|
|
10,000
|
|
Unsecured 6.75% Debentures,
due 2028
|
|
|
150,000
|
|
|
|
150,000
|
|
First Mortgage Bonds
Series P, 10.43% due 2013
|
|
|
8,750
|
|
|
|
10,000
|
|
Rental property, propane and other
term notes due in installments through 2013
|
|
|
5,825
|
|
|
|
7,839
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
2,186,878
|
|
|
|
2,190,142
|
|
Less:
|
|
|
|
|
|
|
|
|
Original issue discount on
unsecured senior notes and debentures
|
|
|
(3,330
|
)
|
|
|
(3,774
|
)
|
Current maturities
|
|
|
(3,186
|
)
|
|
|
(3,264
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,180,362
|
|
|
$
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
In December 2001, we filed a registration statement with the
Securities and Exchange Commission (SEC) to issue, from time to
time, up to $600.0 million in new common stock
and/or debt.
The registration statement was declared effective by the SEC in
January 2002. In July 2004, we sold 9.9 million shares of
our common stock. We used the net proceeds from this offering,
together with borrowings under a bridge financing facility to
consummate the acquisition of TXU Gas operations and pay related
fees and expenses. As a result of the offering, we exhausted the
remaining availability under our December 2001 registration
statement.
In August 2004, we filed another registration statement with the
SEC, which was declared effective by the SEC in September 2004,
under which we could issue, from time to time, up to
$2.2 billion in new common stock
and/or debt.
In October 2004, we sold 16.1 million common shares,
including the underwriters exercise of their overallotment
option, under the new registration statement, generating net
proceeds of $382.5 million before other offering costs.
Additionally, we issued senior unsecured debt under the
registration statement consisting of $400 million of
4.00% Senior Notes due 2009, $500 million of
4.95% Senior Notes due 2014, $200 million of
5.95% Senior Notes due 2034 and $300 million of
floating rate Senior Notes due 2007. The floating rate notes
bear interest at a rate equal to the three-month LIBOR rate plus
0.375 percent per year. At September 30, 2006, the
interest rate on our floating rate debt was 5.882 percent.
The net proceeds from the sale of these senior notes were
$1.39 billion.
The net proceeds from the October 2004 common stock and senior
notes offerings, combined with the net proceeds from our July
2004 offering were used to pay off the $1.7 billion in
outstanding commercial paper backstopped by a senior unsecured
revolving credit agreement, which we entered into in September
2004 for
87
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
bridge financing for the TXU Gas acquisition. Also, as a result
of this refinancing in October 2004, we canceled the senior
unsecured revolving credit facility. After issuing the debt and
equity in October 2004 we had approximately $401.5 million
in availability remaining under the registration statement.
However, we are no longer allowed to issue securities under that
registration statement by applicable state regulatory
commissions. See further discussion in the Liquidity section of
Managements Discussion and Analysis.
In June 2005, we elected to utilize excess cash to repay
$72.5 million in principal on five series of our First
Mortgage Bonds prior to their scheduled maturity. In connection
with the repayment, we paid a $25.0 million make-whole
premium in accordance with the terms of the agreements and
accrued interest of approximately $1.0 million. In
accordance with regulatory requirements, the premium has been
deferred and will be recognized over the remaining original
lives of the First Mortgage Bonds that were repaid.
Short-term
debt
At September 30, 2006 and 2005, there was
$379.3 million and $129.9 million outstanding under
our commercial paper program and $3.1 million and
$14.9 million outstanding under our bank credit facilities.
As of September 30, 2006, our commercial paper had
maturities of less than three months, with interest rates
ranging from 5.47 percent to 5.51 percent.
Credit
facilities
We maintain both committed and uncommitted credit facilities.
Borrowings under our uncommitted credit facilities are made on a
when-and-as-needed
basis at the discretion of the bank. Our credit capacity and the
amount of unused borrowing capacity are affected by the seasonal
nature of the natural gas business and our short-term borrowing
requirements, which are typically highest during colder winter
months. Our working capital needs can vary significantly due to
changes in the price of natural gas charged by suppliers and the
increased gas supplies required to meet customers needs
during periods of cold weather.
Committed
credit facilities
As of September 30, 2006, we had three short-term committed
revolving credit facilities totaling $918 million. The
first facility is a three-year unsecured facility, expiring
October 2008, for $600 million that bears interest at a
base rate or at the LIBOR rate for the applicable interest
period, plus from 0.40 percent to 1.00 percent, based
on the Companys credit ratings, and serves as a backup
liquidity facility for our $600 million commercial paper
program. At September 30, 2006, there was
$379.3 million outstanding under our commercial paper
program.
We have a second unsecured facility in place which is a
364-day
facility for $300 million that bears interest at a base
rate or the LIBOR rate for the applicable interest period, plus
from 0.30 percent to 0.75 percent, based on the
Companys credit ratings. This facility expired in November
2006 and was renewed for one year with no material changes to
its terms and pricing. At September 30, 2006, there were no
borrowings under this facility.
We have a third unsecured facility in place for $18 million
that bears interest at the Federal Funds rate plus
0.5 percent. This facility expired in March 2006 and was
renewed for one year with no material changes to its terms and
pricing. At September 30, 2006, there was $3.1 million
outstanding under this facility.
The availability of funds under our credit facilities is subject
to conditions specified in the respective credit agreements, all
of which we currently satisfy. These conditions include our
compliance with financial covenants and the continued accuracy
of representations and warranties contained in these agreements.
We are required by the financial covenants in our revolving
credit facilities to maintain, at the end of each fiscal
quarter, a ratio of total debt to total capitalization of no
greater than 70 percent. At September 30, 2006, our
88
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
total-debt-to-total-capitalization
ratio, as defined, was 63 percent. In addition, both the
interest margin over the Eurodollar rate and the fee that we pay
on unused amounts under our revolving credit facilities are
subject to adjustment depending upon our credit ratings. The
revolving credit facilities each contain the same limitation
with respect to our total-debt to-total capitalization ratio.
Uncommitted
credit facilities
In November 2005, AEM amended its $250 million uncommitted
demand working capital credit facility to increase the amount of
credit available from $250 million to a maximum of
$580 million. In March 2006, AEM amended and extended this
uncommitted demand working capital credit facility to March 2007.
Borrowings under the amended credit facility can be made either
as revolving loans or offshore rate loans. Revolving loan
borrowings will bear interest at a floating rate equal to a base
rate (defined as the higher of 0.50 percent per annum above
the Federal Funds rate or the lenders prime rate) plus
0.25 percent. Offshore rate loan borrowings will bear
interest at a floating rate equal to a base rate based upon
LIBOR for the applicable interest period, plus an applicable
margin, ranging from 1.25 percent to 1.625 percent per
annum, depending on the excess tangible net worth of AEM, as
defined in the credit facility. Borrowings drawn down under
letters of credit issued by the banks will bear interest at a
floating rate equal to the base rate, as defined above, plus an
applicable margin, which will range from 1.00 percent to
1.875 percent per annum, depending on the excess tangible
net worth of AEM and whether the letters of credit are
swap-related standby letters of credit.
AEM is required by the financial covenants in the credit
facility to maintain a maximum ratio of total liabilities to
tangible net worth of 5 to 1, along with minimum levels of
net working capital ranging from $20 million to
$120 million. Additionally, AEM must maintain a minimum
tangible net worth ranging from $21 million to
$121 million, and must not have a maximum cumulative loss
from March 30, 2005 exceeding $4 million to
$23 million, depending on the total amount of borrowing
elected from time to time by AEM. At September 30, 2006,
AEMs ratio of total liabilities to tangible net worth, as
defined, was 1.24 to 1.
At September 30, 2006, there were no borrowings outstanding
under this credit facility. However, at September 30, 2006,
AEM letters of credit totaling $96.1 million had been
issued under the facility, which reduced the amount available by
a corresponding amount. The amount available under this credit
facility is also limited by various covenants, including
covenants based on working capital. Under the most restrictive
covenant, the amount available to AEM under this credit facility
was $53.9 million at September 30, 2006. This line of
credit is collateralized by substantially all of the assets of
AEM and is guaranteed by AEH.
We also have an unsecured short-term uncommitted credit line for
$25 million that is used for working capital and
letter-of-credit
purposes. There were no borrowings under this uncommitted credit
facility at September 30, 2006, but letters of credit
reduced the amount available by $4.5 million. This
uncommitted line is renewed or renegotiated at least annually
with varying terms, and we pay no fee for the availability of
the line. Borrowings under this line are made on a
when-and-as-available
basis at the discretion of the bank.
AEH, the parent company of AEM, has a $100 million
intercompany uncommitted demand credit facility with the Company
which bears interest at the One Month LIBOR plus
2.75 percent. This facility has been approved by our state
regulators through December 31, 2006. At September 30,
2006, there were no borrowings outstanding under this credit
facility. In July 2006, this facility was renewed for one year
with no material changes to its terms.
In addition, AEM has a $120 million intercompany
uncommitted demand credit facility with AEH for its nonutility
business which bears interest at the One Month LIBOR plus
2.75 percent. Any outstanding amounts under this facility
are subordinated to AEMs $580 million uncommitted
demand credit facility described above. This facility is used to
supplement AEMs $580 million credit facility. At
September 30, 2006, there were no borrowings outstanding
under this credit facility. In July 2006, this facility was
renewed for one year with no material changes to its terms.
89
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt
Covenants
We have other covenants in addition to those described above.
Our Series P First Mortgage Bonds contain provisions that
allow us to prepay the outstanding balance in whole at any time,
after November 2007, subject to a prepayment premium. The First
Mortgage Bonds provide for certain cash flow requirements and
restrictions on additional indebtedness, sale of assets and
payment of dividends. Under the most restrictive of such
covenants, cumulative cash dividends paid after
December 31, 1985 may not exceed the sum of accumulated net
income for periods after December 31, 1985 plus
$9.0 million. At September 30, 2006 approximately
$203.3 million of retained earnings was unrestricted with
respect to the payment of dividends.
As of September 30, 2006, a portion of the Mid-States
Division utility plant assets, totaling $394.2 million, was
subject to a lien under the Indenture of Mortgage of the
Series P First Mortgage Bonds.
We were in compliance with all of our debt covenants as of
September 30, 2006. If we do not comply with our debt
covenants, we may be required to repay our outstanding balances
on demand, provide additional collateral or take other
corrective actions. Our two public debt indentures relating to
our senior notes and debentures, as well as both our revolving
credit agreements, each contain a default provision that is
triggered if outstanding indebtedness arising out of any other
credit agreements in amounts ranging from in excess of
$15 million to in excess of $100 million becomes due
by acceleration or is not paid at maturity. In addition,
AEMs credit agreement contains a cross-default provision
whereby AEM would be in default if it defaults on other
indebtedness, as defined, by at least $250 thousand in the
aggregate. Additionally, this agreement contains a provision
that would limit the amount of credit available if Atmos were
downgraded below an S&P rating of BBB and a Moodys
rating of Baa2.
Except as described above, we have no triggering events in our
debt instruments that are tied to changes in specified credit
ratings or stock price, nor have we entered into any
transactions that would require us to issue equity based on our
credit rating or other triggering events.
Based on the borrowing rates currently available to us for debt
with similar terms and remaining average maturities, the fair
value of long-term debt at September 30, 2006 and 2005 is
estimated, using discounted cash flow analysis, to be
$2,053.9 million and $2,078.3 million.
Maturities of long-term debt at September 30, 2006 were as
follows (in thousands):
|
|
|
|
|
2007
|
|
$
|
3,186
|
|
2008
|
|
|
303,831
|
|
2009
|
|
|
2,034
|
|
2010
|
|
|
401,381
|
|
2011
|
|
|
361,381
|
|
Thereafter
|
|
|
1,115,065
|
|
|
|
|
|
|
|
|
$
|
2,186,878
|
|
|
|
|
|
|
Stock
Issuances
During the years ended September 30, 2006, 2005 and 2004 we
issued 1,200,115, 17,739,691 and 11,323,925 shares of
common stock.
In February 2005, our shareholders approved an amendment to our
Articles of Incorporation to increase the number of authorized
shares from 100 million to 200 million.
90
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In October 2004, we completed the public offering of
16.1 million shares of our common stock including the
underwriters exercise of their overallotment option of
2.1 million shares. The offering was priced at $24.75 and
generated net proceeds of approximately $381.6 million. We
used the net proceeds from this offering, together with net
proceeds of $235.7 million from a public offering we
conducted in July 2004 and $1.39 billion received from the
issuance of senior unsecured notes, to repay the
$1.7 billion in outstanding commercial paper described in
Note 3 and fund the remainder of the purchase price for the
TXU Gas acquisition.
Shareholder
Rights Plan
In November 1997, our Board of Directors declared a dividend
distribution of one right for each outstanding share of our
common stock to shareholders of record at the close of business
on May 10, 1998. Each right entitles the registered holder
to purchase from us a one-tenth share of our common stock at a
purchase price of $8.00 per share, subject to adjustment.
The description and terms of the rights are set forth in a
rights agreement between us and the rights agent.
Subject to exceptions specified in the rights agreement, the
rights will separate from our common stock and a distribution
date will occur upon the earlier of:
|
|
|
|
|
ten business days following a public announcement that a person
or group of affiliated or associated persons has acquired, or
obtained the right to acquire, beneficial ownership of
15 percent or more of the outstanding shares of our common
stock, other than as a result of repurchases of stock by us or
specified inadvertent actions by institutional or other
shareholders;
|
|
|
|
ten business days, or such later date as our Board of Directors
shall determine, following the commencement of a tender offer or
exchange offer that would result in a person or group having
acquired, or obtained the right to acquire, beneficial ownership
of 15 percent or more of the outstanding shares of our
common stock; or
|
|
|
|
ten business days after our Board of Directors shall declare any
person to be an adverse person within the meaning of the rights
plan.
|
The rights expire on May 10, 2008, unless extended prior
thereto by our board of directors or earlier if redeemed by us.
The rights will not have any voting rights. The exercise price
payable and the number of shares of our common stock or other
securities or property issuable upon exercise of the rights are
subject to adjustment from time to time to prevent dilution. We
issue rights when we issue our common stock until the rights
have separated from the common stock. After the rights have
separated from the common stock, we may issue additional rights
if the board of directors deems such issuance to be necessary or
appropriate. The rights have anti-takeover effects
and may cause substantial dilution to a person or entity that
attempts to acquire us on terms not approved by our board of
directors except pursuant to an offer conditioned upon a
substantial number of rights being acquired. The rights should
not interfere with any merger or other business combination
approved by our board of directors because, prior to the time
that the rights become exercisable or transferable, we can
redeem the rights at $.01 per right.
Other
Agreements
In connection with our Mississippi Valley Gas Company
acquisition in December 2002, we issued shares of common stock
under an exemption from registration under the Securities Act of
1933, as amended. In the transaction, we entered into a
registration rights agreement with the former stockholders of
Mississippi Valley Gas Company that required us, on no more than
two occasions, and with some limitations, to file a registration
statement under the Securities Act within 60 days of their
request for an offering designed to achieve a wide distribution
of shares through underwriters selected by us. We also granted
rights to these shareholders, subject to some limitations, to
participate in future registered offerings of our securities
until December 3, 2005. No
91
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
registration rights issued to the former stockholders of MVG, as
discussed above, were exercised prior to the expiration of the
registration rights agreement on December 3, 2005. The
former stockholders of MVG also agreed, for up to five years
from the closing of the acquisition, or until December 3,
2007, and with some exceptions, not to sell or transfer shares
representing more than 1 percent of our total outstanding
voting securities to any person or group or any shares to a
person or group who would hold more than 9.9 percent of our
total outstanding voting securities after the sale or transfer.
This restriction, and other agreed restrictions on the ability
of these shareholders to acquire additional shares, participate
in proxy solicitations or act to seek control, may be deemed to
have an anti-takeover effect.
|
|
8.
|
Stock and
Other Compensation Plans
|
Stock-Based
Compensation Plans
1998
Long-Term Incentive Plan
In August 1998, the Board of Directors approved and adopted the
1998 Long-Term Incentive Plan, which became effective in October
1998 after approval by our shareholders. The Long-Term Incentive
Plan is a comprehensive, long-term incentive compensation plan
providing for discretionary awards of incentive stock options,
non-qualified stock options, stock appreciation rights, bonus
stock, time-lapse restricted stock, performance-based restricted
stock units and stock units to certain employees and
non-employee directors of Atmos and its subsidiaries. The
objectives of this plan include attracting and retaining the
best personnel, providing for additional performance incentives
and promoting our success by providing employees with the
opportunity to acquire common stock. We are authorized to grant
awards for up to a maximum of four million shares of common
stock under this plan subject to certain adjustment provisions.
As of September 30, 2006, non-qualified stock options,
bonus stock, time-lapse restricted stock, performance-based
restricted stock units and stock units had been issued under
this plan, and 731,745 shares were available for future
issuance. The option price of the stock options issued under
this plan is equal to the market price of our stock at the date
of grant. These stock options expire 10 years from the date
of the grant and vest annually over a service period ranging
from one to three years.
We used the Black-Scholes pricing model to estimate the fair
value of each option granted with the following weighted average
assumptions for 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Valuation
Assumptions(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Life
(years)(2)
|
|
|
7
|
|
|
|
7
|
|
|
|
7
|
|
Interest
rate(3)
|
|
|
4.6
|
%
|
|
|
4.2
|
%
|
|
|
4.3
|
%
|
Volatility(4)
|
|
|
20.3
|
%
|
|
|
21.3
|
%
|
|
|
22.8
|
%
|
Dividend yield
|
|
|
4.8
|
%
|
|
|
4.8
|
%
|
|
|
4.8
|
%
|
|
|
|
(1) |
|
Beginning on the date of adoption of SFAS 123(R),
forfeitures are estimated based on historical experience. Prior
to the date of adoption, forfeitures were recorded as they
occurred. |
|
(2) |
|
The expected life of stock options is estimated based on
historical experience. |
|
(3) |
|
The interest rate is based on the U.S. Treasury constant
maturity interest rate whose term is consistent with the
expected life of the stock options. |
|
(4) |
|
The volatility is estimated based on historical and current
stock data for the Company. |
92
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of activity for grants of stock options under the 1998
Long-Term Incentive Plan follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
|
Options
|
|
|
Price
|
|
|
Options
|
|
|
Price
|
|
|
Options
|
|
|
Price
|
|
|
Outstanding at beginning of year
|
|
|
964,704
|
|
|
$
|
22.20
|
|
|
|
1,492,177
|
|
|
$
|
22.10
|
|
|
|
1,827,310
|
|
|
$
|
21.91
|
|
Granted
|
|
|
93,196
|
|
|
|
26.19
|
|
|
|
23,432
|
|
|
|
25.95
|
|
|
|
8,118
|
|
|
|
24.44
|
|
Exercised
|
|
|
(40,582
|
)
|
|
|
22.21
|
|
|
|
(547,907
|
)
|
|
|
22.08
|
|
|
|
(342,252
|
)
|
|
|
20.91
|
|
Forfeited
|
|
|
(166
|
)
|
|
|
21.23
|
|
|
|
(2,998
|
)
|
|
|
22.81
|
|
|
|
(999
|
)
|
|
|
22.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of
year(1)
|
|
|
1,017,152
|
|
|
$
|
22.57
|
|
|
|
964,704
|
|
|
$
|
22.20
|
|
|
|
1,492,177
|
|
|
$
|
22.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of
year(2)
|
|
|
991,778
|
|
|
$
|
22.48
|
|
|
|
798,574
|
|
|
$
|
22.22
|
|
|
|
1,006,859
|
|
|
$
|
22.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted-average remaining contractual life for outstanding
options was 5.4 years, 6.0 years, and 7.0 years
for fiscal years 2006, 2005 and 2004. The aggregate intrinsic
value of outstanding options was $3.7 million,
$3.5 million and $5.4 million for fiscal years 2006,
2005 and 2004. |
|
(2) |
|
The weighted-average remaining contractual life for exercisable
options was 5.3 years, 5.7 years, and 6.5 years
for fiscal years 2006, 2005 and 2004. The aggregate intrinsic
value of exercisable options was $3.6 million,
$2.9 million and $3.7 million for fiscal years 2006,
2005 and 2004. |
Information about outstanding and exercisable options under the
1998 Long-Term Incentive Plan, as of September 30, 2006,
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Options Exercisable
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Remaining
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Contractual
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
Range of Exercise Prices
|
|
Options
|
|
|
Life (In Years)
|
|
|
Price
|
|
|
Options
|
|
|
Price
|
|
|
$15.65 to $20.24
|
|
|
64,833
|
|
|
|
3.4
|
|
|
$
|
15.66
|
|
|
|
64,833
|
|
|
$
|
15.66
|
|
$20.25 to $22.99
|
|
|
547,414
|
|
|
|
5.8
|
|
|
$
|
21.87
|
|
|
|
547,414
|
|
|
$
|
21.87
|
|
$23.00 to $26.19
|
|
|
404,905
|
|
|
|
5.1
|
|
|
$
|
24.62
|
|
|
|
379,531
|
|
|
$
|
24.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$15.65 to $26.19
|
|
|
1,017,152
|
|
|
|
5.4
|
|
|
$
|
22.57
|
|
|
|
991,778
|
|
|
$
|
22.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The stock options had a weighted average fair value per share on
the date of grant of $3.74 in 2006, $3.69 in 2005 and $3.82 in
2004. Net cash proceeds from the exercise of stock options
during the years ended September 30, 2006, 2005 and 2004
were $0.9 million, $12.1 million and
$7.2 million. The associated income tax benefit from stock
options exercised during the years ended September 30,
2006, 2005 and 2004 were less than $0.1 million,
$1.3 million and $0.6 million. The total intrinsic
value of options exercised during the years ended
September 30, 2006, 2005 and 2004 were less than
$0.1 million, $2.0 million and $1.2 million.
As of September 30, 2006, there was less than
$0.1 million of total unrecognized compensation cost
related to nonvested stock options. That cost is expected to be
recognized over a weighted-average period of 1.3 years.
Restricted
Stock Plans
As noted above, the 1998 Long-Term Incentive Plan provides for
discretionary awards of restricted stock to help attract, retain
and reward employees and non-employee directors of Atmos and its
subsidiaries. Certain of these awards vest based upon the
passage of time and other awards vest based upon the passage of
time
93
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and the achievement of specified performance targets. The
associated expense is recognized ratably over the vesting
period. The following summarizes information regarding the
restricted stock plan:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
Number of
|
|
|
Average
|
|
|
Number of
|
|
|
Average
|
|
|
|
Restricted
|
|
|
Grant-Date
|
|
|
Restricted
|
|
|
Grant-Date
|
|
|
Restricted
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at beginning of year
|
|
|
592,490
|
|
|
$
|
25.32
|
|
|
|
345,519
|
|
|
$
|
23.72
|
|
|
|
107,837
|
|
|
$
|
21.19
|
|
Granted
|
|
|
440,016
|
|
|
|
26.80
|
|
|
|
294,834
|
|
|
|
26.78
|
|
|
|
240,686
|
|
|
|
24.78
|
|
Vested
|
|
|
(265,546
|
)
|
|
|
24.42
|
|
|
|
(36,106
|
)
|
|
|
21.97
|
|
|
|
(2,175
|
)
|
|
|
15.65
|
|
Forfeited
|
|
|
(20,184
|
)
|
|
|
26.95
|
|
|
|
(11,757
|
)
|
|
|
24.70
|
|
|
|
(829
|
)
|
|
|
23.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of year
|
|
|
746,776
|
|
|
$
|
26.49
|
|
|
|
592,490
|
|
|
$
|
25.32
|
|
|
|
345,519
|
|
|
$
|
23.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2006, there was $12.4 million of
total unrecognized compensation cost related to nonvested
restricted shares granted under the 1998 Long-Term Incentive
Plan. That cost is expected to be recognized over a
weighted-average period of 1.9 years. The fair value of
restricted stock vested during the years ended
September 30, 2006, 2005 and 2004 was $6.5 million,
$0.8 million and less than $0.1 million.
Other
Plans
Direct
Stock Purchase Plan
We maintain a Direct Stock Purchase Plan which allows
participants to have all or part of their cash dividends paid
quarterly in additional shares of our common stock. Through
March 2004, participants were permitted to reinvest their cash
dividends at a three percent discount from market prices.
Effective April 2004, the three percent discount on reinvested
dividends was eliminated and the minimum initial investment
required to join the plan was increased to $1,250. Direct Stock
Purchase Plan participants may purchase additional shares of
Atmos common stock as often as weekly with voluntary cash
payments of at least $25, up to an annual maximum of $100,000.
Outside
Directors
Stock-For-Fee
Plan
In November 1994, the Board adopted the Outside Directors
Stock-for-Fee
Plan which was approved by the shareholders of Atmos in February
1995 and was amended and restated in November 1997. The plan
permits non-employee directors to receive all or part of their
annual retainer and meeting fees in stock rather than in cash.
Equity
Incentive and Deferred Compensation Plan for Non-Employee
Directors
In November 1998, the Board of Directors adopted the Equity
Incentive and Deferred Compensation Plan for Non-Employee
Directors which was approved by the shareholders of Atmos in
February 1999. This plan amended the Atmos Energy Corporation
Deferred Compensation Plan for Outside Directors adopted by the
Company in May 1990 and replaced the pension payable under the
Companys Retirement Plan for Non-Employee Directors. The
plan provides non-employee directors of Atmos with the
opportunity to defer receipt, until retirement, of compensation
for services rendered to the Company, invest deferred
compensation into either a cash account or a stock account and
to receive an annual grant of share units for each year of
service on the Board.
Other
Discretionary Compensation Plans
We created the Variable Pay Plan in fiscal 1999 for our utility
segment employees to give each employee an opportunity to share
in the success of Atmos based on the achievement of key
performance measures
94
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
considered critical to achieving business objectives for a given
year. These performance measures may include earnings growth
objectives, improved cash flow objectives or crucial customer
satisfaction and safety results. We monitor progress towards the
achievement of the performance measures throughout the year and
record accruals based upon the expected payout using the best
estimates available at the time the accrual is recorded.
We implemented the Annual Incentive Plan in October 2001 to give
the employees in our nonutility segments an opportunity to share
in the success of the nonutility operations. The plan is based
upon the net earnings of the nonutility operations and has
minimum and maximum thresholds. The plan must meet the minimum
threshold in order for the plan to be funded and distributed to
employees. We monitor the progress toward the achievement of the
thresholds throughout the year and record accruals based upon
the expected payout using the best estimates available at the
time the accrual is recorded.
|
|
9.
|
Retirement
and Post-Retirement Employee Benefit Plans
|
We have both funded and unfunded noncontributory defined benefit
plans that together cover substantially all of our employees. We
also maintain post-retirement plans that provide health care
benefits to retired employees. Finally, we sponsor defined
contribution plans which cover substantially all employees.
These plans are discussed in further detail below.
Defined
Benefit Plans
Employee
Pension Plans
As of September 30, 2006, we maintained two defined benefit
plans: the Atmos Energy Corporation Pension Account Plan (the
Plan) and the Atmos Energy Corporation Retirement Plan for
Mississippi Valley Gas Union Employees (the Union Plan)
(collectively referred to as the Plans). The Plans are held
within the Atmos Energy Corporation Master Retirement Trust (the
Master Trust).
The Plan is a cash balance pension plan, that was established
effective January 1999 and covers substantially all employees of
Atmos. Opening account balances were established for
participants as of January 1999 equal to the present value
of their respective accrued benefits under the pension plans
which were previously in effect as of December 31, 1998.
The Plan credits an allocation to each participants
account at the end of each year according to a formula based on
the participants age, service and total pay (excluding
incentive pay).
The Plan also provides for an additional annual allocation based
upon a participants age as of January 1, 1999 for
those participants who were participants in the prior pension
plans. The Plan will credit this additional allocation each year
through December 31, 2008. In addition, at the end of each
year, a participants account will be credited with
interest on the employees prior year account balance. A
special grandfather benefit also applies through
December 31, 2008, for participants who were at least
age 50 as of January 1, 1999, and who were
participants in one of the prior plans on December 31,
1998. Participants fully vest in their account balances after
five years of service and may choose to receive their account
balances as a lump sum or an annuity.
The Union Plan is a defined benefit plan that covers
substantially all full-time union employees in our Mississippi
Division. Under this plan, benefits are based upon years of
benefit service and average final earnings. Participants vest in
the plan after five years and will receive their benefit in an
annuity.
Generally, our funding policy is to contribute annually an
amount in accordance with the requirements of the Employee
Retirement Income Security Act of 1974. However, additional
voluntary contributions are made from time to time as considered
necessary. Contributions are intended to provide not only for
benefits attributed to service to date but also for those
expected to be earned in the future.
95
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During fiscal 2006, we voluntarily contributed $2.9 million
to the Union Plan. The current year contribution achieved a
desired level of funding by satisfying the minimum funding
requirements while maximizing the tax deductible contribution
for this plan for plan year 2005. During fiscal 2005, we
voluntarily contributed $3.0 million to the Master Trust to
maintain the level of funding we desire relative to our
accumulated benefit obligation. We made the contribution because
declining high yield corporate bond yields in the period leading
up to our June 30, 2005 measurement date resulted in an
increase in the present value of our plan liabilities. We are
not required to make a minimum funding contribution during
fiscal 2007 nor do we anticipate making any voluntary
contributions during fiscal 2007.
We manage the Master Trusts assets with the objective of
achieving a rate of return net of inflation of approximately
four percent per year. We make investment decisions and evaluate
performance on a medium term horizon of at least three to five
years. We also consider our current financial status when making
recommendations and decisions regarding the Master Trusts
assets. Finally, we strive to ensure the Master Trusts
assets are appropriately invested to maintain an acceptable
level of risk and meet the Master Trusts long term asset
allocation policy.
To achieve these objectives, we invest the Master Trusts
assets in equity securities, fixed income securities, interests
in commingled pension trust funds and cash and cash equivalents.
Investments in equity securities are diversified among the
markets various subsectors to diversify risk and maximize
returns. Fixed income securities are invested in investment
grade securities. Cash equivalents are invested in securities
that either are short term (less than 180 days) or readily
convertible to cash with modest risk.
The following table presents asset allocation information for
the Master Trust as of September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Allocation
|
|
|
|
Targeted
|
|
September 30
|
|
Security Class
|
|
Allocation Range
|
|
2006
|
|
|
2005
|
|
|
Domestic equities
|
|
35%-55%
|
|
|
44.3
|
%
|
|
|
45.0
|
%
|
International equities
|
|
10%-20%
|
|
|
15.6
|
%
|
|
|
17.9
|
%
|
Fixed income
|
|
10%-30%
|
|
|
18.8
|
%
|
|
|
18.1
|
%
|
Company stock
|
|
0%-10%
|
|
|
9.2
|
%
|
|
|
9.1
|
%
|
Other assets
|
|
5%-15%
|
|
|
10.7
|
%
|
|
|
9.6
|
%
|
Cash and equivalents
|
|
N/A
|
|
|
1.4
|
%
|
|
|
0.3
|
%
|
At September 30, 2006 and 2005, the Plan held
1,169,700 shares of Atmos common stock, which represented
9.2 percent and 9.1 percent of total Master Trust
assets. These shares generated dividend income for the Plan of
approximately $1.5 million during both fiscal 2006 and 2005.
96
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our employee pension plan expenses 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 and
assumed discount rates and demographic data. We review the
estimates and assumptions underlying our employee pension plans
annually based upon a June 30 measurement date. The
development of our assumptions is fully described in our
significant accounting policies in Note 2. The actuarial
assumptions used to determine the pension liability for the
Plans were determined as of June 30, 2006 and 2005 and the
actuarial assumptions used to determine the net periodic pension
cost for the Plans were determined as of June 30, 2005,
2004 and 2003. These assumptions are presented in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Liability
|
|
|
Pension Cost
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Discount rate
|
|
|
6.30
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.00
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
Expected return on plan assets
|
|
|
8.25
|
%
|
|
|
8.50
|
%
|
|
|
8.50
|
%
|
|
|
8.75
|
%
|
|
|
9.00
|
%
|
The following table presents the Plans accumulated benefit
obligation, projected benefit obligation and funded status as of
September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Accumulated benefit
obligation
|
|
$
|
316,078
|
|
|
$
|
348,383
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit
obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of
year
|
|
$
|
359,924
|
|
|
$
|
312,997
|
|
Service cost
|
|
|
13,465
|
|
|
|
10,401
|
|
Interest cost
|
|
|
17,932
|
|
|
|
19,412
|
|
Actuarial loss (gain)
|
|
|
(36,748
|
)
|
|
|
43,313
|
|
Benefits paid
|
|
|
(28,109
|
)
|
|
|
(26,199
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
326,464
|
|
|
|
359,924
|
|
Change in plan
assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at
beginning of year
|
|
|
355,939
|
|
|
|
346,162
|
|
Actual return on plan assets
|
|
|
32,005
|
|
|
|
32,976
|
|
Employer contributions
|
|
|
2,879
|
|
|
|
3,000
|
|
Benefits paid
|
|
|
(28,109
|
)
|
|
|
(26,199
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end
of year
|
|
|
362,714
|
|
|
|
355,939
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
36,250
|
|
|
|
(3,985
|
)
|
Unrecognized prior service cost
|
|
|
(4,980
|
)
|
|
|
(5,939
|
)
|
Unrecognized net loss
|
|
|
65,646
|
|
|
|
119,270
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
96,916
|
|
|
$
|
109,346
|
|
|
|
|
|
|
|
|
|
|
97
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net periodic pension cost for the Plans for 2006, 2005 and 2004
is recorded as operating expense and included the following
components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension
cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
13,465
|
|
|
$
|
10,401
|
|
|
$
|
7,696
|
|
Interest cost
|
|
|
17,932
|
|
|
|
19,412
|
|
|
|
19,691
|
|
Expected return on assets
|
|
|
(25,598
|
)
|
|
|
(27,541
|
)
|
|
|
(30,097
|
)
|
Amortization of prior service cost
|
|
|
(959
|
)
|
|
|
(1,028
|
)
|
|
|
(1,028
|
)
|
Recognized actuarial loss
|
|
|
10,469
|
|
|
|
6,276
|
|
|
|
6,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
15,309
|
|
|
$
|
7,520
|
|
|
$
|
2,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Executive Benefits Plans
We have a nonqualified Supplemental Executive Benefits Plan
which provides additional pension, disability and death benefits
to the officers and certain other employees of Atmos. The
Supplemental Plan was amended and restated in August 1998. In
addition, in August 1998, we adopted the Performance-Based
Supplemental Executive Benefits Plan which covers all employees
who become officers or division presidents after August 12,
1998 or any other employees selected by our Board of Directors
at its discretion.
Similar to our employee pension plans, we review the estimates
and assumptions underlying our supplemental executive benefit
plans annually based upon a June 30 measurement date using
the same techniques as our employee pension plans. The actuarial
assumptions used to determine the pension liability for the
supplemental plans were determined as of June 30, 2006 and
2005 and the actuarial assumptions used to determine the net
periodic pension cost for the supplemental plans were determined
as of June 30, 2005, 2004 and 2003. These assumptions are
presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Liability
|
|
Pension Cost
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
2004
|
|
Discount rate
|
|
|
6.30
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.00
|
%
|
Rate of compensation increase
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
98
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the supplemental plans
accumulated benefit obligation, projected benefit obligation and
funded status as of September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Accumulated benefit
obligation
|
|
$
|
79,209
|
|
|
$
|
86,661
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit
obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of
year
|
|
$
|
97,941
|
|
|
$
|
73,998
|
|
Service cost
|
|
|
3,001
|
|
|
|
2,144
|
|
Interest cost
|
|
|
4,955
|
|
|
|
4,658
|
|
Actuarial loss (gain)
|
|
|
(14,618
|
)
|
|
|
20,637
|
|
Benefits paid
|
|
|
(3,780
|
)
|
|
|
(3,496
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
87,499
|
|
|
|
97,941
|
|
Change in plan
assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at
beginning of year
|
|
|
|
|
|
|
|
|
Employer contribution
|
|
|
3,780
|
|
|
|
3,496
|
|
Benefits paid
|
|
|
(3,780
|
)
|
|
|
(3,496
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end
of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(87,499
|
)
|
|
|
(97,941
|
)
|
Unrecognized prior service cost
|
|
|
1,684
|
|
|
|
2,706
|
|
Unrecognized net loss
|
|
|
22,927
|
|
|
|
40,334
|
|
|
|
|
|
|
|
|
|
|
Accrued pension cost
|
|
$
|
(62,888
|
)
|
|
$
|
(54,901
|
)
|
|
|
|
|
|
|
|
|
|
Assets for the supplemental plans are held in separate rabbi
trusts and comprise the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
|
|
|
|
|
|
|
|
|
|
Holding
|
|
|
Market
|
|
|
|
Cost
|
|
|
Gain
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
As of September 30,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
30,562
|
|
|
$
|
1,099
|
|
|
$
|
31,661
|
|
Foreign equity mutual funds
|
|
|
5,975
|
|
|
|
1,542
|
|
|
|
7,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36,537
|
|
|
$
|
2,641
|
|
|
$
|
39,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30,
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic equity mutual funds
|
|
$
|
28,902
|
|
|
$
|
897
|
|
|
$
|
29,799
|
|
Foreign equity mutual funds
|
|
|
5,133
|
|
|
|
328
|
|
|
|
5,461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
34,035
|
|
|
$
|
1,225
|
|
|
$
|
35,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At September 30, 2006, we maintained investments in one
domestic equity mutual fund and one domestic bond fund that were
in unrealized loss positions as of September 30, 2006.
Information concerning unrealized losses for our supplemental
plan assets follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than 12 Months
|
|
|
12 Months or More
|
|
|
|
|
|
|
Unrealized
|
|
|
|
|
|
Unrealized
|
|
|
|
Fair Value
|
|
|
Loss
|
|
|
Fair Value
|
|
|
Loss
|
|
|
|
(In thousands)
|
|
|
Domestic equity mutual funds
|
|
$
|
19,963
|
|
|
$
|
773
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Because these funds are only used to fund the supplemental
plans, we evaluate investment performance over a long-term
horizon. Based upon our intent and ability to hold these
investments, the short-term nature of the impairment as of
September 30, 2006 and our ability to direct the source of
the payments in order to maximize the life of the portfolio, the
improved investment returns in the last year and the fact that
these funds continue to receive good ratings from mutual fund
rating companies, we do not consider this impairment to be
other-than-temporary.
Net periodic pension cost for the supplemental plans for 2006,
2005 and 2004 is recorded as operating expense and included the
following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Components of net periodic pension
cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,001
|
|
|
$
|
2,144
|
|
|
$
|
2,037
|
|
Interest cost
|
|
|
4,955
|
|
|
|
4,658
|
|
|
|
4,324
|
|
Amortization of transition asset
|
|
|
|
|
|
|
4
|
|
|
|
96
|
|
Amortization of prior service cost
|
|
|
1,022
|
|
|
|
1,022
|
|
|
|
1,022
|
|
Recognized actuarial loss
|
|
|
2,789
|
|
|
|
1,290
|
|
|
|
1,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension cost
|
|
$
|
11,767
|
|
|
$
|
9,118
|
|
|
$
|
8,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures For Defined Benefit Plans with Accumulated Benefit
Obligations in Excess of Plan Assets
The following summarizes key information for our defined benefit
plans with accumulated benefit obligations in excess of plan
assets. For fiscal 2005 the accumulated benefit obligation for
the MVG plan exceeded the fair value of plan assets. For fiscal
2006 and 2005 the accumulated benefit obligation for our
supplemental plans exceeded the fair value of plan assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Pension Plans
|
|
|
Supplemental Plans
|
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Projected Benefit Obligation
|
|
$
|
13,550
|
|
|
$
|
87,499
|
|
|
$
|
97,941
|
|
Accumulated Benefit Obligation
|
|
|
10,738
|
|
|
|
79,209
|
|
|
|
86,661
|
|
Fair Value of Plan Assets
|
|
|
6,465
|
|
|
|
|
|
|
|
|
|
100
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Estimated
Future Benefit Payments
The following benefit payments for our defined benefit plans,
which reflect expected future service, as appropriate, are
expected to be paid in the following years:
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
|
Supplemental
|
|
|
|
Plans
|
|
|
Plans
|
|
|
|
(In thousands)
|
|
|
2007
|
|
$
|
32,119
|
|
|
$
|
3,729
|
|
2008
|
|
|
27,923
|
|
|
|
4,242
|
|
2009
|
|
|
28,588
|
|
|
|
4,512
|
|
2010
|
|
|
29,811
|
|
|
|
5,262
|
|
2011
|
|
|
29,399
|
|
|
|
5,287
|
|
2012-2016
|
|
|
122,553
|
|
|
|
29,913
|
|
Postretirement
Benefits
At September 30, 2006, we sponsored the Retiree Medical
Plan for Retirees and Disabled Employees of Atmos Energy
Corporation (the Atmos Retiree Medical Plan). Effective
December 31, 2004, the Atmos Energy Corporation Retiree
Welfare Benefits Plan for Certain MVG Non-Union Employees and
the Atmos Energy Corporation Retiree Welfare Benefits Plan for
MVG Union Employees merged into the Atmos Retiree Medical Plan.
This plan provides medical and prescription drug protection to
all qualified participants based on their date of retirement.
The Plan provides different levels of benefits depending on the
level of coverage chosen by the participants and the terms of
predecessor plans; however, we generally pay 80 percent of
the projected net claims and administrative costs and
participants pay the remaining 20 percent of this cost.
On October 1, 2004, in connection with the acquisition of
TXU Gas, we transitioned certain employees from TXU Gas to Atmos
Energy Corporation. Although we did not assume the existing
employee benefit liabilities or plans of TXU Gas, we received a
credit of $18.9 million against the purchase price to
permit us to provide partial past service credits for retiree
medical benefits under the Atmos Retiree Medical Plan. The
$18.9 million credit approximated the actuarially
determined present value of the accumulated benefits related to
the past service of the transitioned employees on the
acquisition date.
Generally, our funding policy is to contribute annually an
amount in accordance with the requirements of the Employee
Retirement Income Security Act of 1974. However, additional
voluntary contributions are made annually as considered
necessary. Contributions are intended to provide not only for
benefits attributed to service to date but also for those
expected to be earned in the future. We expect to contribute
$11.4 million to our postretirement benefits plans during
fiscal 2007.
We maintain a formal investment policy with respect to the
assets in our postretirement benefits plans to ensure the assets
funding the postretirement benefit plans are appropriately
invested to maintain an acceptable level of risk. We also
consider our current financial status when making
recommendations and decisions regarding the postretirement
benefits plans.
101
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We currently invest the assets funding our postretirement
benefit plans in money market funds, equity mutual funds, fixed
income funds and a balanced fund. The following table presents
asset allocation information for the postretirement benefit plan
assets as of September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
Actual Allocation
|
|
|
September 30
|
Security Class
|
|
2006
|
|
2005
|
|
Diversified investment
fund(1)
|
|
|
100
|
%
|
|
|
97.2
|
%
|
Cash and cash equivalents
|
|
|
|
|
|
|
2.8
|
%
|
|
|
|
(1) |
|
This fund invests in a diversified portfolio of common stocks,
preferred stocks and fixed income securities. It may invest up
to 75 percent of assets in common stocks and convertible
securities. |
Similar to our employee pension and supplemental plans, we
review the estimates and assumptions underlying our supplemental
executive benefit plans annually based upon a June 30
measurement date using the same techniques as our employee
pension plans. The actuarial assumptions used to determine the
pension liability for our postretirement plan were determined as
of June 30, 2006 and 2005 and the actuarial assumptions
used to determine the net periodic pension cost for the
postretirement plan were determined as of June 30, 2005,
2004 and 2003. The assumptions are presented in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
|
|
|
|
Liability
|
|
|
Postretirement Cost
|
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Discount rate
|
|
|
6.30
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
6.25
|
%
|
|
|
6.19
|
%
|
Expected return on plan assets
|
|
|
5.20
|
%
|
|
|
5.30
|
%
|
|
|
5.30
|
%
|
|
|
5.30
|
%
|
|
|
5.30
|
%
|
Initial trend rate
|
|
|
8.00
|
%
|
|
|
9.00
|
%
|
|
|
9.00
|
%
|
|
|
10.00
|
%
|
|
|
9.00
|
%
|
Ultimate trend rate
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
Ultimate trend reached in
|
|
|
2010
|
|
|
|
2010
|
|
|
|
2010
|
|
|
|
2010
|
|
|
|
2008
|
|
102
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the postretirement plans
benefit obligation and funded status as of September 30,
2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Change in benefit
obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of
year
|
|
$
|
170,930
|
|
|
$
|
125,189
|
|
Service cost
|
|
|
13,083
|
|
|
|
9,968
|
|
Interest cost
|
|
|
8,840
|
|
|
|
9,369
|
|
Plan participants
contributions
|
|
|
1,340
|
|
|
|
2,131
|
|
Actuarial loss (gain)
|
|
|
(22,657
|
)
|
|
|
16,449
|
|
Acquisition
|
|
|
|
|
|
|
18,878
|
|
Benefits paid
|
|
|
(10,695
|
)
|
|
|
(11,054
|
)
|
Subsidy payments
|
|
|
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
160,901
|
|
|
|
170,930
|
|
Change in plan
assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at
beginning of year
|
|
|
39,843
|
|
|
|
36,408
|
|
Actual return on plan assets
|
|
|
3,703
|
|
|
|
2,365
|
|
Employer contributions
|
|
|
10,609
|
|
|
|
9,993
|
|
Plan participants
contributions
|
|
|
1,340
|
|
|
|
2,131
|
|
Benefits paid
|
|
|
(10,695
|
)
|
|
|
(11,054
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end
of year
|
|
|
44,800
|
|
|
|
39,843
|
|
|
|
|
|
|
|
|
|
|
Reconciliation:
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(116,101
|
)
|
|
|
(131,087
|
)
|
Unrecognized transition obligation
|
|
|
11,154
|
|
|
|
12,665
|
|
Unrecognized prior service cost
|
|
|
33
|
|
|
|
394
|
|
Unrecognized net loss
|
|
|
3,060
|
|
|
|
28,513
|
|
|
|
|
|
|
|
|
|
|
Accrued postretirement cost
|
|
$
|
(101,854
|
)
|
|
$
|
(89,515
|
)
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement cost for 2006, 2005 and 2004 is
recorded as operating expense and included the components
presented below. The 2006, 2005 and 2004 amounts reflect the
impact of adopting the provisions of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the Act)
beginning in the second quarter of fiscal 2004 as the plan is
considered actuarially equivalent to Medicare
Part D.
103
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Components of net periodic
postretirement cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
13,083
|
|
|
$
|
9,968
|
|
|
$
|
5,941
|
|
Interest cost
|
|
|
8,840
|
|
|
|
9,369
|
|
|
|
7,355
|
|
Expected return on assets
|
|
|
(2,187
|
)
|
|
|
(2,070
|
)
|
|
|
(1,523
|
)
|
Amortization of transition
obligation
|
|
|
1,511
|
|
|
|
1,511
|
|
|
|
1,511
|
|
Amortization of prior service cost
|
|
|
361
|
|
|
|
386
|
|
|
|
386
|
|
Recognized actuarial loss
|
|
|
1,280
|
|
|
|
622
|
|
|
|
635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement cost
|
|
$
|
22,888
|
|
|
$
|
19,786
|
|
|
$
|
14,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed health care cost trend rates have a significant effect
on the amounts reported for the plan. A one-percentage point
change in assumed health care cost trend rates would have the
following effects on the latest actuarial calculations:
|
|
|
|
|
|
|
|
|
|
|
1-Percentage
|
|
1-Percentage
|
|
|
Point Increase
|
|
Point Decrease
|
|
|
(In thousands)
|
|
Effect on total service and
interest cost components
|
|
$
|
3,782
|
|
|
$
|
(3,064
|
)
|
Effect on postretirement benefit
obligation
|
|
$
|
17,678
|
|
|
$
|
(14,974
|
)
|
We are currently recovering other postretirement benefits costs
through our regulated rates under SFAS 106 accrual
accounting in substantially all of our service areas. Other
postretirement benefits costs have been specifically addressed
in rate orders in each jurisdiction served by our Mid-States
Division and our Mississippi Division or have been included in a
rate case and not disallowed. Management believes that accrual
accounting in accordance with SFAS 106 is appropriate and
will continue to seek rate recovery of accrual-based expenses in
its ratemaking jurisdictions that have not yet approved the
recovery of these expenses.
Estimated
Future Benefit Payments
The following benefit payments paid by us, retirees and
prescription drug subsidy payments for our postretirement
benefit plans, which reflect expected future service, as
appropriate, are expected to be paid in the following years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Company
|
|
|
Retiree
|
|
|
Subsidy
|
|
|
Postretirement
|
|
|
|
Payments
|
|
|
Payments
|
|
|
Payments
|
|
|
Benefits
|
|
|
|
(In thousands)
|
|
|
2007
|
|
$
|
11,408
|
|
|
$
|
2,249
|
|
|
$
|
127
|
|
|
$
|
13,784
|
|
2008
|
|
|
10,180
|
|
|
|
2,574
|
|
|
|
32
|
|
|
|
12,786
|
|
2009
|
|
|
11,404
|
|
|
|
2,743
|
|
|
|
|
|
|
|
14,147
|
|
2010
|
|
|
12,520
|
|
|
|
3,015
|
|
|
|
|
|
|
|
15,535
|
|
2011
|
|
|
13,621
|
|
|
|
3,278
|
|
|
|
|
|
|
|
16,899
|
|
2012-2016
|
|
|
86,065
|
|
|
|
20,698
|
|
|
|
|
|
|
|
106,763
|
|
104
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Defined
Contribution Plans
As of September 30, 2006, we maintained two defined
contribution benefit plans: the Atmos Energy Corporation
Retirement Savings Plan and Trust (the Retirement Savings Plan)
and the Atmos Energy Corporation Savings Plan for MVG Union
Employees (the Union 401K Plan).
The Retirement Savings Plan covers substantially all employees
and is subject to the provisions of Section 401(k) of the
Internal Revenue Code. Participants may elect a salary reduction
ranging from a minimum of one percent up to a maximum of
65 percent of eligible compensation, as defined by the
Plan, not to exceed the maximum allowed by the Internal Revenue
Service. We match 100 percent of a participants
contributions, limited to four percent of the participants
salary, in Atmos common stock. However, participants have the
option to immediately transfer this matching contribution into
other funds held within the plan. Participants are eligible to
receive matching contributions after completing one year of
service. Participants are also permitted to take out loans
against their accounts subject to certain restrictions.
The Union 401K Plan covers substantially all Mississippi
Division employees who are members of the International Chemical
Workers Union Council, United Food and Commercial Workers Union
International (the Union) and is subject to the provisions of
Section 401(k) of the Internal Revenue Code. Employees of
the Union automatically become participants of the Union 401K
plan on the date of union employment. We match 50 percent
of a participants contribution, limited to six percent of
the participants eligible contribution. Participants are
also permitted to take out loans against their accounts subject
to certain restrictions.
Matching contributions to our defined contribution plans are
expensed as incurred and amounted to $7.0 million,
$5.7 million, and $4.6 million for 2006, 2005 and
2004. The Board of Directors may also approve discretionary
contributions, subject to the provisions of the Internal Revenue
Code of 1986 and applicable regulations of the Internal Revenue
Service. No discretionary contributions were made for 2006, 2005
or 2004. At September 30, 2006 and 2005, the Retirement
Savings Plan held 3.2 percent and 3.1 percent of our
outstanding common stock.
|
|
10.
|
Details
of Selected Consolidated Balance Sheet Captions
|
The following tables provide additional information regarding
the composition of certain of our balance sheet captions.
Accounts
receivable
Accounts receivable was comprised of the following at
September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Billed accounts receivable
|
|
$
|
321,279
|
|
|
$
|
381,469
|
|
Unbilled revenue
|
|
|
44,607
|
|
|
|
62,337
|
|
Other accounts receivable
|
|
|
22,429
|
|
|
|
26,120
|
|
|
|
|
|
|
|
|
|
|
Total accounts receivable
|
|
|
388,315
|
|
|
|
469,926
|
|
Less: allowance for doubtful
accounts
|
|
|
(13,686
|
)
|
|
|
(15,613
|
)
|
|
|
|
|
|
|
|
|
|
Net accounts receivable
|
|
$
|
374,629
|
|
|
$
|
454,313
|
|
|
|
|
|
|
|
|
|
|
105
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
current assets
Other current assets as of September 30, 2006 and 2005 were
comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Assets from risk management
activities
|
|
$
|
12,553
|
|
|
$
|
107,913
|
|
Deferred gas cost
|
|
|
44,992
|
|
|
|
38,173
|
|
Taxes receivable
|
|
|
56,034
|
|
|
|
|
|
Current deferred tax asset
|
|
|
18,943
|
|
|
|
67,365
|
|
Prepaid expenses
|
|
|
16,379
|
|
|
|
13,334
|
|
Current portion of leased assets
receivable
|
|
|
2,973
|
|
|
|
2,973
|
|
Materials and supplies
|
|
|
6,088
|
|
|
|
7,502
|
|
Other
|
|
|
11,990
|
|
|
|
978
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
169,952
|
|
|
$
|
238,238
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
Property, plant and equipment was comprised of the following as
of September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Production plant
|
|
$
|
12,563
|
|
|
$
|
19,401
|
|
Storage plant
|
|
|
118,902
|
|
|
|
116,708
|
|
Transmission plant
|
|
|
863,882
|
|
|
|
753,499
|
|
Distribution plant
|
|
|
3,404,220
|
|
|
|
3,164,316
|
|
General plant
|
|
|
541,852
|
|
|
|
502,189
|
|
Intangible plant
|
|
|
85,059
|
|
|
|
75,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,026,478
|
|
|
|
4,631,684
|
|
Construction in progress
|
|
|
74,830
|
|
|
|
133,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,101,308
|
|
|
|
4,765,610
|
|
Less: accumulated depreciation and
amortization
|
|
|
(1,472,152
|
)
|
|
|
(1,391,243
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
3,629,156
|
|
|
$
|
3,374,367
|
|
|
|
|
|
|
|
|
|
|
106
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Deferred
charges and other assets
Deferred charges and other assets as of September 30, 2006
and 2005 were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Pension plan assets in excess of
plan obligations
|
|
$
|
96,916
|
|
|
$
|
109,346
|
|
Marketable securities
|
|
|
39,178
|
|
|
|
35,260
|
|
Long-term receivable on leased
assets
|
|
|
16,440
|
|
|
|
19,413
|
|
Regulatory assets
|
|
|
30,823
|
|
|
|
37,844
|
|
Deferred financing costs
|
|
|
42,673
|
|
|
|
47,792
|
|
Assets from risk management
activities
|
|
|
6,186
|
|
|
|
735
|
|
Other
|
|
|
2,109
|
|
|
|
26,553
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
234,325
|
|
|
$
|
276,943
|
|
|
|
|
|
|
|
|
|
|
Other
current liabilities
Other current liabilities as of September 30, 2006 and 2005
were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Customer deposits
|
|
$
|
102,555
|
|
|
$
|
89,918
|
|
Accrued employee costs
|
|
|
27,276
|
|
|
|
26,409
|
|
Deferred gas costs
|
|
|
68,959
|
|
|
|
134,048
|
|
Accrued interest
|
|
|
54,892
|
|
|
|
53,675
|
|
Liabilities from risk management
activities
|
|
|
30,669
|
|
|
|
61,920
|
|
Taxes payable
|
|
|
50,673
|
|
|
|
66,083
|
|
Post-retirement obligations
|
|
|
8,850
|
|
|
|
5,300
|
|
Regulatory cost of removal accrual
|
|
|
15,114
|
|
|
|
11,565
|
|
Other
|
|
|
29,463
|
|
|
|
54,450
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
388,451
|
|
|
$
|
503,368
|
|
|
|
|
|
|
|
|
|
|
107
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Deferred
credits and other liabilities
Deferred credits and other liabilities as of September 30,
2006 and 2005 were comprised of the following accounts.
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Post-retirement obligations
|
|
$
|
93,004
|
|
|
$
|
84,215
|
|
Nonqualified retirement plan
obligation
|
|
|
62,888
|
|
|
|
54,901
|
|
Customer advances for construction
|
|
|
17,481
|
|
|
|
18,872
|
|
Liabilities from risk management
activities
|
|
|
276
|
|
|
|
15,316
|
|
Deferred revenue
|
|
|
4,049
|
|
|
|
5,488
|
|
Regulatory liabilities
|
|
|
10,825
|
|
|
|
8,084
|
|
Asset retirement obligation
|
|
|
15,070
|
|
|
|
|
|
Other
|
|
|
785
|
|
|
|
12,739
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
204,378
|
|
|
$
|
199,615
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per share for the years ended
September 30 are calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income
|
|
$
|
147,737
|
|
|
$
|
135,785
|
|
|
$
|
86,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic income per
share weighted average common shares
|
|
|
80,731
|
|
|
|
78,508
|
|
|
|
54,021
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted and other shares
|
|
|
551
|
|
|
|
360
|
|
|
|
281
|
|
Stock options
|
|
|
108
|
|
|
|
144
|
|
|
|
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted income per
share weighted average common shares
|
|
|
81,390
|
|
|
|
79,012
|
|
|
|
54,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
basic
|
|
$
|
1.83
|
|
|
$
|
1.73
|
|
|
$
|
1.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share
diluted
|
|
$
|
1.82
|
|
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There were no
out-of-the-money
options excluded from the computation of diluted earnings per
share for the year ended September 30, 2006 and 2005. There
were approximately 3,000
out-of-the-money
options excluded from the computation of diluted earnings per
share for the year ended September 30, 2004 as their
exercise price was greater than the average market price of the
common stock during that period.
108
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The components of income tax expense from continuing operations
for 2006, 2005 and 2004 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
838
|
|
|
$
|
61,508
|
|
|
$
|
9,003
|
|
State
|
|
|
2,623
|
|
|
|
8,569
|
|
|
|
2,021
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
77,154
|
|
|
|
11,453
|
|
|
|
35,970
|
|
State
|
|
|
9,024
|
|
|
|
1,217
|
|
|
|
5,079
|
|
Investment tax credits
|
|
|
(486
|
)
|
|
|
(514
|
)
|
|
|
(535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
89,153
|
|
|
$
|
82,233
|
|
|
$
|
51,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliations of the provision for income taxes computed at
the statutory rate to the reported provisions for income taxes
from continuing operations for 2006, 2005 and 2004 are set forth
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Tax at statutory rate of 35%
|
|
$
|
82,912
|
|
|
$
|
76,306
|
|
|
$
|
48,218
|
|
Common stock dividends deductible
for tax reporting
|
|
|
(1,180
|
)
|
|
|
(1,088
|
)
|
|
|
(985
|
)
|
State taxes (net of federal
benefit)
|
|
|
7,570
|
|
|
|
6,361
|
|
|
|
4,615
|
|
Other, net
|
|
|
(149
|
)
|
|
|
654
|
|
|
|
(310
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
89,153
|
|
|
$
|
82,233
|
|
|
$
|
51,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Deferred income taxes reflect the tax effect of differences
between the basis of assets and liabilities for book and tax
purposes. The tax effect of temporary differences that give rise
to significant components of the deferred tax liabilities and
deferred tax assets at September 30, 2006 and 2005 are
presented below:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Costs expensed for book purposes
and capitalized for tax purposes
|
|
$
|
6,469
|
|
|
$
|
1,299
|
|
Accruals not currently deductible
for tax purposes
|
|
|
7,709
|
|
|
|
13,319
|
|
Customer advances
|
|
|
6,643
|
|
|
|
8,455
|
|
Nonqualified benefit plans
|
|
|
26,337
|
|
|
|
24,869
|
|
Postretirement benefits
|
|
|
37,558
|
|
|
|
33,176
|
|
Treasury lock agreement
|
|
|
12,589
|
|
|
|
14,698
|
|
Unamortized investment tax credit
|
|
|
680
|
|
|
|
864
|
|
Regulatory liabilities
|
|
|
1,460
|
|
|
|
9,836
|
|
Tax net operating loss and credit
carryforwards
|
|
|
5,623
|
|
|
|
855
|
|
Gas cost adjustments
|
|
|
19,434
|
|
|
|
36,432
|
|
Other, net
|
|
|
4,525
|
|
|
|
9,781
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
129,027
|
|
|
|
153,584
|
|
Deferred tax
liabilities:
|
|
|
|
|
|
|
|
|
Difference in net book value and
net tax value of assets
|
|
|
(364,438
|
)
|
|
|
(317,834
|
)
|
Pension funding
|
|
|
(37,188
|
)
|
|
|
(42,597
|
)
|
Regulatory assets
|
|
|
(1,695
|
)
|
|
|
(13,021
|
)
|
Cost capitalized for book purposes
and expensed for tax purposes
|
|
|
(1,618
|
)
|
|
|
(2,739
|
)
|
Difference between book and tax on
mark to market accounting
|
|
|
(9,536
|
)
|
|
|
(82
|
)
|
Other, net
|
|
|
(1,781
|
)
|
|
|
(2,153
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(416,256
|
)
|
|
|
(378,426
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
$
|
(287,229
|
)
|
|
$
|
(224,842
|
)
|
|
|
|
|
|
|
|
|
|
SFAS No. 109 deferred
credits for rate regulated entities
|
|
$
|
2,687
|
|
|
$
|
2,833
|
|
|
|
|
|
|
|
|
|
|
We have tax carryforwards amounting to $5.6 million. The
tax carryforwards include net operating losses for federal
purposes amounting to $4.3 million and state net operating
losses amounting to $1.3 million. The federal net operating
loss carryforwards will expire in 2026. Depending on the
jurisdiction in which the net operating loss was generated, the
state net operating losses will begin to expire between 2011 and
2026.
The Internal Revenue Service is currently conducting a routine
examination of our fiscal 2002, 2003 and 2004 tax returns. We
believe all material tax items which relate to the years under
audit have been properly accrued.
110
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
13.
|
Commitments
and Contingencies
|
Litigation
Colorado-Kansas
Division
We are a defendant in a lawsuit originally filed by Quinque
Operating Company, Tom Boles and Robert Ditto in September 1999
in the District Court of Stevens County, Kansas against more
than 200 companies in the natural gas industry. The
plaintiffs, who purport to represent a class of royalty owners,
allege that the defendants have underpaid royalties on gas taken
from wells situated on non-federal and non-Indian lands in
Kansas, predicated upon allegations that the defendants
gas measurements were inaccurate. The plaintiffs have not
specifically alleged an amount of damages. We are also a
defendant, along with over 50 other companies in the natural gas
industry, in another proposed class action lawsuit filed in the
same court by Will Price, Tom Boles and The Cooper Clarke
Foundation in May 2003 involving similar allegations. We believe
that the plaintiffs claims are lacking in merit and we
intend to vigorously defend these actions. While the results
cannot be predicted with certainty, we believe the final outcome
of such litigation will not have a material adverse effect on
our financial conditions, results of operations or net cash
flows. We were also a defendant in another lawsuit entitled
In Re Natural Gas Royalties Qui Tam Litigation, involving
similar allegations filed in June 1997 in the United States
District Court for the District of Colorado, which was later
transferred to the United States District Court for the District
of Wyoming, where it was consolidated with approximately 50
additional lawsuits in October 1999. On October 20, 2006,
the District Court granted the defendants motion to
dismiss this lawsuit for lack of subject matter jurisdiction.
United
Cities Propane Gas, Inc.
United Cities Propane Gas, Inc., one of our wholly-owned
subsidiaries, was a party to an action filed in June 2000 that
was pending in the Circuit Court of Sevier County, Tennessee.
The plaintiffs claims arose out of injuries alleged to
have been caused by a low-level propane explosion. The
plaintiffs were seeking to recover damages of
$13.0 million. The case was settled on November 14,
2006. As the settlement amount was fully covered by insurance,
the settlement did not have a material adverse effect on our
financial condition, results of operations or net cash flows.
We are a party to other litigation and claims that arose in the
ordinary course of our business, including certain litigation
and claims that arose in the ordinary course of the business of
TXU Gas Company, the natural gas distribution and pipeline
operations we acquired on October 1, 2004. While the
results of such litigation and claims cannot be predicted with
certainty, we believe the final outcome of such litigation and
claims will not have a material adverse effect on our financial
condition, results of operations or net cash flows.
Environmental
Matters
Former
Manufactured Gas Plant Sites
We are the owner or previous owner of former manufactured gas
plant sites in Johnson City and Bristol, Tennessee, Keokuk,
Iowa, and Hannibal, Missouri, which were used to supply gas
prior to the availability of natural gas. The gas manufacturing
process resulted in certain byproducts and residual materials,
including coal tar. The manufacturing process used by our
predecessors was an acceptable and satisfactory process at the
time such operations were being conducted. Under current
environmental protection laws and regulations, we may be
responsible for response actions with respect to such materials
if response actions are necessary.
United Cities Gas Company and the Tennessee Department of
Environment and Conservation (TDEC) entered into a consent order
effective in January 1997, to facilitate the investigation,
removal and remediation of the Johnson City site. Prior to our
merger with United Cities Gas Company in July 1997, United
Cities Gas
111
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company began the implementation of the consent order in the
first quarter of fiscal 1997, which will continue for the
foreseeable future. The investigative phase of the work at the
site has been completed, and an interim removal action was
completed in June 2001. We installed four groundwater monitoring
wells at the site in 2002 and have submitted the analytical
results to the TDEC. We completed a risk assessment report that
has been approved by the TDEC as well as a feasibility study for
this site, which was submitted to the TDEC in October 2003. The
feasibility study recommends a remedial action that will limit
the use of and access to the impacted soil, cap the site with
the addition of a clay fill and geosynthetic liner and
groundwater monitoring for a period of up to 30 years. The
feasibility study was approved by the TDEC in February 2005. The
estimated cost of the remedial action is $1.5 million,
which is comprised primarily of operating and maintenance costs
that would be associated with a groundwater monitoring project.
In January 2006, the TDEC issued a Record of Decision approving
the remedial action recommended in the feasibility study. The
Tennessee Regulatory Authority granted us permission to defer,
until our next rate case in Tennessee, all costs incurred in
Tennessee in connection with state and federally mandated
environmental control requirements.
In March 2002, the TDEC contacted us about conducting an
investigation at a former manufactured gas plant located in
Bristol, Tennessee. We agreed to perform a preliminary
investigation at the site, which we completed in June 2002. The
investigation identified manufactured gas plant residual
materials in the soil beneath the site, and we have proposed
performing a focused removal action to remove any such
residuals. The TDEC requested that the focused removal action be
conducted pursuant to a voluntary agreement. In April 2004, we
entered into a voluntary consent agreement with the TDEC for the
performance of the removal action and the removal action was
completed in November 2004. In September 2005, we filed site use
limitations on the property in the local property records,
including restrictions on the use of the site to commercial and
industrial purposes and a prohibition of the use of groundwater
for use as drinking water were filed. In February 2006, we
received a Completion Letter from the TDEC informing us that no
further action is required at this site pursuant to the
voluntary consent agreement with the TDEC.
In July 1998, we entered into an Abatement Order on Consent with
the Missouri Department of Natural Resources to address the
former manufactured gas plant located in Hannibal, Missouri. We
agreed to perform a removal action and a subsequent site
evaluation and to reimburse the response costs incurred by the
state of Missouri in connection with the property. The removal
action was conducted and completed in August 1998, and the
site-evaluation field work was conducted in August 1999. A risk
assessment for the site has been approved by the Missouri
Department of Natural Resources. In preparation for the risk
assessment, we executed and recorded certain site-use
limitations, including restricting use of the site to commercial
and industrial purposes and prohibiting the withdrawal of
groundwater for use as drinking water. In addition, we have
installed a geosynthetic liner over the surface of the site.
In 1995, United Cities Gas Company entered into an agreement
with a third party to resolve its share of the costs of
additional investigations and environmental-response actions for
soil contamination at a former manufactured gas plant in Keokuk,
Iowa. However, the extent of groundwater contamination at the
site, if any, which is not covered by the agreement, has yet to
be determined.
As of September 30, 2006, we had incurred costs of
approximately $2.3 million for the investigations of the
Johnson City and Bristol, Tennessee, and Hannibal, Missouri
sites.
We are a party to other environmental matters and claims that
have arisen in the ordinary course of our business. While the
ultimate results of response actions to these environmental
matters and claims cannot be predicted with certainty, we
believe the final outcome of such response actions will not have
a material adverse effect on our financial condition, results of
operations or net cash flows because we believe that the
expenditures related to such response actions will either be
recovered through rates, shared with other parties or are
adequately covered by insurance.
112
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Purchase
Commitments
AEM has commitments to purchase physical quantities of natural
gas under contracts indexed to the forward NYMEX strip or fixed
price contracts. At September 30, 2006, AEM was committed
to purchase 61.7 Bcf within one year, 51.2 Bcf within
one to three years and 0.8 Bcf after three years under
indexed contracts. AEM is committed to purchase 2.4 Bcf
within one year and 0.1 Bcf within one to three years under
fixed price contracts with prices ranging from $3.40 to $12.00.
Purchases under these contracts totaled $2,124.3 million,
$1,421.2 million and $1,252.2 million for 2006, 2005
and 2004.
Our utility divisions, except for our Mid-Tex Division, maintain
supply contracts with several vendors that generally cover a
period of up to one year. Commitments for estimated base gas
volumes are established under these contracts on a monthly basis
at contractually negotiated prices. Commitments for incremental
daily purchases are made as necessary during the month in
accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to
ensure a reliable source of gas for our customers in its service
area which obligate it to purchase specified volumes at market
prices. The estimated commitments under these contracts as of
September 30, 2006 are as follows (in thousands):
|
|
|
|
|
2007
|
|
$
|
560,461
|
|
2008
|
|
|
101,702
|
|
2009
|
|
|
9,091
|
|
2010
|
|
|
8,518
|
|
2011
|
|
|
8,517
|
|
Thereafter
|
|
|
19,928
|
|
|
|
|
|
|
|
|
$
|
708,217
|
|
|
|
|
|
|
Leasing
Operations
Atmos Power Systems, Inc. constructs electric peaking
power-generating plants and associated facilities and enters
into agreements to either lease or sell these plants. We
completed a sales-type lease transaction for one distributed
electric generation plant in 2001 and a second sales-type lease
transaction in 2003. In connection with these lease
transactions, as of September 30, 2006 and 2005, we had
receivables of $19.4 million and $22.4 million and
recognized income of $1.7 million, $1.6 million and
$1.9 million for fiscal years 2006, 2005 and 2004. The
future minimum lease payments to be received for each of the
five succeeding years are as follows:
|
|
|
|
|
|
|
Minimum
|
|
|
|
Lease
|
|
|
|
Receipts
|
|
|
|
(In thousands)
|
|
|
2007
|
|
$
|
2,973
|
|
2008
|
|
|
2,973
|
|
2009
|
|
|
2,973
|
|
2010
|
|
|
2,973
|
|
2011
|
|
|
2,973
|
|
Thereafter
|
|
|
4,548
|
|
|
|
|
|
|
Total minimum lease receipts
|
|
$
|
19,413
|
|
|
|
|
|
|
113
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Capital
and Operating Leases
We have entered into non-cancelable operating leases for office
and warehouse space used in our operations. The remaining lease
terms range from one to 20 years and generally provide for
the payment of taxes, insurance and maintenance by the lessee.
Renewal options exist for certain of these leases. We have also
entered into capital leases for division offices and operating
facilities. Property, plant and equipment included amounts for
capital leases of $5.8 million at September 30, 2006
and 2005. Accumulated depreciation for these capital leases
totaled $4.2 million and $3.8 million at
September 30, 2006 and 2005. Depreciation expense for these
assets is included in consolidated depreciation expense on the
consolidated statement of income.
The related future minimum lease payments at September 30,
2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
Operating
|
|
|
|
Leases
|
|
|
Leases
|
|
|
|
(In thousands)
|
|
|
2007
|
|
$
|
433
|
|
|
$
|
15,959
|
|
2008
|
|
|
362
|
|
|
|
15,463
|
|
2009
|
|
|
311
|
|
|
|
14,694
|
|
2010
|
|
|
291
|
|
|
|
13,502
|
|
2011
|
|
|
186
|
|
|
|
13,410
|
|
Thereafter
|
|
|
1,194
|
|
|
|
103,778
|
|
|
|
|
|
|
|
|
|
|
Total minimum lease payments
|
|
|
2,777
|
|
|
$
|
176,806
|
|
|
|
|
|
|
|
|
|
|
Less amount representing interest
|
|
|
1,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of net minimum lease
payments
|
|
$
|
1,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated lease and rental expense amounted to
$11.4 million, $9.5 million and $8.1 million for
fiscal 2006, 2005 and 2004.
|
|
15.
|
Concentration
of Credit Risk
|
Credit risk is the risk of financial loss to us if a customer
fails to perform its contractual obligations. We engage in
transactions for the purchase and sale of products and services
with major companies in the energy industry and with industrial,
commercial, residential and municipal energy consumers. These
transactions principally occur in the southern and midwestern
regions of the United States. We believe that this geographic
concentration does not contribute significantly to our overall
exposure to credit risk. Credit risk associated with trade
accounts receivable for the utility segment is mitigated by the
large number of individual customers and diversity in our
customer base. Due to minimal receivables, the credit risk for
our other nonutility segment is not significant.
Customer diversification also helps mitigate AEMs exposure
to credit risk. AEM maintains credit policies with respect to
its counterparties that it believes minimizes overall credit
risk. Where appropriate, such policies include the evaluation of
a prospective counterpartys financial condition,
collateral requirements and the use of standardized agreements
that facilitate the netting of cash flows associated with a
single counterparty. AEM also monitors the financial condition
of existing counterparties on an ongoing basis. Customers not
meeting minimum standards are required to provide adequate
assurance of financial performance.
AEM maintains a provision for credit losses based upon factors
surrounding the credit risk of customers, historical trends and
other information. We believe, based on our credit policies and
our provisions for credit
114
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
losses, that our financial position, results of operations and
cash flows will not be materially affected as a result of
nonperformance by any single counterparty.
AEMs estimated credit exposure is monitored in terms of
the percentage of its customers that are rated as investment
grade versus non-investment grade. Credit exposure is defined as
the total of (1) accounts receivable, (2) delivered,
but unbilled physical sales and
(3) mark-to-market
exposure for sales and purchases. Investment grade
determinations are set internally by AEMs credit
department, but are primarily based on external ratings provided
by Moodys Investors Service Inc. (Moodys)
and/or
Standard & Poors Corporation (S&P). For
non-rated entities, the default rating for municipalities is
investment grade, while the default rating for non-guaranteed
industrials and commercials is non-investment grade. The
following table shows the percentages related to the investment
ratings as of September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
Investment grade
|
|
|
40
|
%
|
|
|
49
|
%
|
Non-investment grade
|
|
|
60
|
%
|
|
|
51
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
The following table presents our derivative counterparty credit
exposure by operating segment based upon the unrealized fair
value of our derivative contracts that represent assets as of
September 30, 2006. Investment grade counterparties have
minimum credit ratings of BBB-, assigned by Standard &
Poors Rating Group; or Baa3, assigned by Moodys
Investor Service. Non-investment grade counterparties are
composed of counterparties that are below investment grade or
that have not been assigned an internal investment grade rating
due to the short-term nature of the contracts associated with
that counterparty. This category is composed of numerous smaller
counterparties, none of which is individually significant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
|
|
|
|
Segment(1)
|
|
|
Segment
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Investment grade counterparties
|
|
$
|
|
|
|
$
|
16,001
|
|
|
$
|
16,001
|
|
Non-investment grade counterparties
|
|
|
|
|
|
|
2,738
|
|
|
|
2,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
18,739
|
|
|
$
|
18,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Counterparty risk for our utility segment is minimized because
hedging gains and losses are passed through to our customers. |
|
|
16.
|
Supplemental
Cash Flow Disclosures
|
Supplemental disclosures of cash flow information for 2006, 2005
and 2004 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash paid for interest
|
|
$
|
149,031
|
|
|
$
|
103,418
|
|
|
$
|
65,700
|
|
Cash paid for income taxes
|
|
$
|
77,265
|
|
|
$
|
51,490
|
|
|
$
|
1,677
|
|
There were no significant noncash investing and financing
transactions during fiscal 2006, 2005 and 2004. All cash flows
and non cash activities related to our commodity derivatives are
considered as operating activities.
115
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Atmos Energy Corporation and its subsidiaries are engaged
primarily in the natural gas utility business as well as certain
nonutility businesses. We distribute natural gas through sales
and transportation arrangements to approximately
3.2 million residential, commercial, public-authority and
industrial customers throughout our seven regulated utility
divisions, which cover service areas located in 12 states.
In addition, we transport natural gas for others through our
distribution system.
Through our nonutility businesses, we provide natural gas
management and marketing services to industrial customers,
municipalities and other local distribution companies located in
22 states. Additionally, we provide natural gas
transportation and storage services to certain of our utility
operations and to third parties.
Our operations are divided into four segments:
|
|
|
|
|
The utility segment, which includes our regulated natural gas
distribution and related sales operations,
|
|
|
|
The natural gas marketing segment, which includes a variety of
nonregulated natural gas management services,
|
|
|
|
The pipeline and storage segment, which includes our regulated
and nonregulated natural gas transmission and storage
services and
|
|
|
|
The other nonutility segment, which includes all of our other
nonregulated nonutility operations.
|
Our determination of reportable segments considers the strategic
operating units under which we manage sales of various products
and services to customers in differing regulatory environments.
Although our utility segment operations are geographically
dispersed, they are reported as a single segment as each utility
division has similar economic characteristics. The accounting
policies of the segments are the same as those described in the
summary of significant accounting policies. We evaluate
performance based on net income or loss of the respective
operating units. Interest expense is allocated pro rata to each
segment based upon our net investment in each segment. Income
taxes are allocated to each segment as if each segments
taxes were calculated on a separate return basis.
116
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Summarized income statements and capital expenditures by segment
are shown in the following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2006
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
3,649,851
|
|
|
$
|
2,418,856
|
|
|
$
|
81,857
|
|
|
$
|
1,799
|
|
|
$
|
|
|
|
$
|
6,152,363
|
|
Intersegment revenues
|
|
|
740
|
|
|
|
737,668
|
|
|
|
78,710
|
|
|
|
4,099
|
|
|
|
(821,217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,650,591
|
|
|
|
3,156,524
|
|
|
|
160,567
|
|
|
|
5,898
|
|
|
|
(821,217
|
)
|
|
|
6,152,363
|
|
Purchased gas cost
|
|
|
2,725,534
|
|
|
|
3,025,897
|
|
|
|
838
|
|
|
|
|
|
|
|
(816,476
|
)
|
|
|
4,935,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
925,057
|
|
|
|
130,627
|
|
|
|
159,729
|
|
|
|
5,898
|
|
|
|
(4,741
|
)
|
|
|
1,216,570
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
357,519
|
|
|
|
22,223
|
|
|
|
53,641
|
|
|
|
5,013
|
|
|
|
(4,978
|
)
|
|
|
433,418
|
|
Depreciation and amortization
|
|
|
164,493
|
|
|
|
1,834
|
|
|
|
19,166
|
|
|
|
103
|
|
|
|
|
|
|
|
185,596
|
|
Taxes, other than income
|
|
|
178,204
|
|
|
|
4,335
|
|
|
|
9,064
|
|
|
|
390
|
|
|
|
|
|
|
|
191,993
|
|
Impairment of long-lived assets
|
|
|
22,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
723,163
|
|
|
|
28,392
|
|
|
|
81,871
|
|
|
|
5,506
|
|
|
|
(4,978
|
)
|
|
|
833,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
201,894
|
|
|
|
102,235
|
|
|
|
77,858
|
|
|
|
392
|
|
|
|
237
|
|
|
|
382,616
|
|
Miscellaneous income
|
|
|
9,506
|
|
|
|
2,598
|
|
|
|
2,554
|
|
|
|
4,151
|
|
|
|
(17,928
|
)
|
|
|
881
|
|
Interest charges
|
|
|
126,489
|
|
|
|
8,510
|
|
|
|
25,331
|
|
|
|
3,968
|
|
|
|
(17,691
|
)
|
|
|
146,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
84,911
|
|
|
|
96,323
|
|
|
|
55,081
|
|
|
|
575
|
|
|
|
|
|
|
|
236,890
|
|
Income tax expense
|
|
|
31,909
|
|
|
|
37,757
|
|
|
|
19,457
|
|
|
|
30
|
|
|
|
|
|
|
|
89,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
53,002
|
|
|
$
|
58,566
|
|
|
$
|
35,624
|
|
|
$
|
545
|
|
|
$
|
|
|
|
$
|
147,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
307,742
|
|
|
$
|
909
|
|
|
$
|
116,673
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
425,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
117
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2005
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
3,102,041
|
|
|
$
|
1,783,926
|
|
|
$
|
73,880
|
|
|
$
|
2,026
|
|
|
$
|
|
|
|
$
|
4,961,873
|
|
Intersegment revenues
|
|
|
1,099
|
|
|
|
322,352
|
|
|
|
79,409
|
|
|
|
3,276
|
|
|
|
(406,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,103,140
|
|
|
|
2,106,278
|
|
|
|
153,289
|
|
|
|
5,302
|
|
|
|
(406,136
|
)
|
|
|
4,961,873
|
|
Purchased gas cost
|
|
|
2,195,774
|
|
|
|
2,044,305
|
|
|
|
6,811
|
|
|
|
|
|
|
|
(402,654
|
)
|
|
|
3,844,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
907,366
|
|
|
|
61,973
|
|
|
|
146,478
|
|
|
|
5,302
|
|
|
|
(3,482
|
)
|
|
|
1,117,637
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
346,594
|
|
|
|
18,444
|
|
|
|
50,773
|
|
|
|
4,153
|
|
|
|
(3,683
|
)
|
|
|
416,281
|
|
Depreciation and amortization
|
|
|
159,497
|
|
|
|
1,896
|
|
|
|
16,504
|
|
|
|
108
|
|
|
|
|
|
|
|
178,005
|
|
Taxes, other than income
|
|
|
164,910
|
|
|
|
648
|
|
|
|
8,915
|
|
|
|
223
|
|
|
|
|
|
|
|
174,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
671,001
|
|
|
|
20,988
|
|
|
|
76,192
|
|
|
|
4,484
|
|
|
|
(3,683
|
)
|
|
|
768,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
236,365
|
|
|
|
40,985
|
|
|
|
70,286
|
|
|
|
818
|
|
|
|
201
|
|
|
|
348,655
|
|
Miscellaneous income
|
|
|
6,776
|
|
|
|
771
|
|
|
|
2,030
|
|
|
|
2,575
|
|
|
|
(10,131
|
)
|
|
|
2,021
|
|
Interest charges
|
|
|
112,382
|
|
|
|
3,405
|
|
|
|
24,579
|
|
|
|
2,222
|
|
|
|
(9,930
|
)
|
|
|
132,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
130,759
|
|
|
|
38,351
|
|
|
|
47,737
|
|
|
|
1,171
|
|
|
|
|
|
|
|
218,018
|
|
Income tax expense
|
|
|
49,642
|
|
|
|
14,947
|
|
|
|
17,138
|
|
|
|
506
|
|
|
|
|
|
|
|
82,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
81,117
|
|
|
$
|
23,404
|
|
|
$
|
30,599
|
|
|
$
|
665
|
|
|
$
|
|
|
|
$
|
135,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
300,574
|
|
|
$
|
649
|
|
|
$
|
31,960
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
333,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended September 30, 2004
|
|
|
|
|
|
|
Natural Gas
|
|
|
Pipeline
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
and Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Operating revenues from external
parties
|
|
$
|
1,636,636
|
|
|
$
|
1,279,424
|
|
|
$
|
1,617
|
|
|
$
|
2,360
|
|
|
$
|
|
|
|
$
|
2,920,037
|
|
Intersegment revenues
|
|
|
1,092
|
|
|
|
339,178
|
|
|
|
18,141
|
|
|
|
1,033
|
|
|
|
(359,444
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,637,728
|
|
|
|
1,618,602
|
|
|
|
19,758
|
|
|
|
3,393
|
|
|
|
(359,444
|
)
|
|
|
2,920,037
|
|
Purchased gas cost
|
|
|
1,134,594
|
|
|
|
1,571,971
|
|
|
|
9,383
|
|
|
|
|
|
|
|
(358,102
|
)
|
|
|
2,357,846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
503,134
|
|
|
|
46,631
|
|
|
|
10,375
|
|
|
|
3,393
|
|
|
|
(1,342
|
)
|
|
|
562,191
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
195,471
|
|
|
|
15,692
|
|
|
|
2,533
|
|
|
|
2,150
|
|
|
|
(1,376
|
)
|
|
|
214,470
|
|
Depreciation and amortization
|
|
|
92,954
|
|
|
|
2,089
|
|
|
|
1,488
|
|
|
|
116
|
|
|
|
|
|
|
|
96,647
|
|
Taxes, other than income
|
|
|
54,819
|
|
|
|
1,124
|
|
|
|
1,061
|
|
|
|
375
|
|
|
|
|
|
|
|
57,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
343,244
|
|
|
|
18,905
|
|
|
|
5,082
|
|
|
|
2,641
|
|
|
|
(1,376
|
)
|
|
|
368,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
159,890
|
|
|
|
27,726
|
|
|
|
5,293
|
|
|
|
752
|
|
|
|
34
|
|
|
|
193,695
|
|
Miscellaneous income
|
|
|
5,847
|
|
|
|
843
|
|
|
|
289
|
|
|
|
8,290
|
|
|
|
(5,762
|
)
|
|
|
9,507
|
|
Interest charges
|
|
|
65,399
|
|
|
|
2,711
|
|
|
|
1,053
|
|
|
|
2,002
|
|
|
|
(5,728
|
)
|
|
|
65,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
100,338
|
|
|
|
25,858
|
|
|
|
4,529
|
|
|
|
7,040
|
|
|
|
|
|
|
|
137,765
|
|
Income tax expense
|
|
|
37,242
|
|
|
|
9,225
|
|
|
|
1,762
|
|
|
|
3,309
|
|
|
|
|
|
|
|
51,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
63,096
|
|
|
$
|
16,633
|
|
|
$
|
2,767
|
|
|
$
|
3,731
|
|
|
$
|
|
|
|
$
|
86,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
189,291
|
|
|
$
|
520
|
|
|
$
|
474
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
190,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our revenues by products and
services for the year ended September 30.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Utility revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
2,068,736
|
|
|
$
|
1,791,172
|
|
|
$
|
923,773
|
|
Commercial
|
|
|
1,061,783
|
|
|
|
869,722
|
|
|
|
400,704
|
|
Industrial
|
|
|
276,186
|
|
|
|
229,649
|
|
|
|
155,336
|
|
Agricultural
|
|
|
40,664
|
|
|
|
27,889
|
|
|
|
31,851
|
|
Public authority and other
|
|
|
103,936
|
|
|
|
86,853
|
|
|
|
77,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas sales revenues
|
|
|
3,551,305
|
|
|
|
3,005,285
|
|
|
|
1,588,842
|
|
Transportation revenues
|
|
|
61,475
|
|
|
|
58,897
|
|
|
|
30,622
|
|
Other gas revenues
|
|
|
37,071
|
|
|
|
37,859
|
|
|
|
17,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility revenues
|
|
|
3,649,851
|
|
|
|
3,102,041
|
|
|
|
1,636,636
|
|
Natural gas marketing revenues
|
|
|
2,418,856
|
|
|
|
1,783,926
|
|
|
|
1,279,424
|
|
Pipeline and storage revenues
|
|
|
81,857
|
|
|
|
73,880
|
|
|
|
1,617
|
|
Other nonutility revenues
|
|
|
1,799
|
|
|
|
2,026
|
|
|
|
2,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,152,363
|
|
|
$
|
4,961,873
|
|
|
$
|
2,920,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at September 30, 2006 and 2005 by
segment is presented in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006
|
|
|
|
|
|
|
Natural
|
|
|
Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
3,083,301
|
|
|
$
|
7,531
|
|
|
$
|
537,028
|
|
|
$
|
1,296
|
|
|
$
|
|
|
|
$
|
3,629,156
|
|
Investment in subsidiaries
|
|
|
281,143
|
|
|
|
(2,155
|
)
|
|
|
|
|
|
|
|
|
|
|
(278,988
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
8,738
|
|
|
|
45,481
|
|
|
|
|
|
|
|
21,596
|
|
|
|
|
|
|
|
75,815
|
|
Cash held on deposit in margin
account
|
|
|
|
|
|
|
35,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,647
|
|
Assets from risk management
activities
|
|
|
|
|
|
|
13,164
|
|
|
|
19,040
|
|
|
|
|
|
|
|
(19,651
|
)
|
|
|
12,553
|
|
Other current assets
|
|
|
714,472
|
|
|
|
261,435
|
|
|
|
26,325
|
|
|
|
8,119
|
|
|
|
(16,821
|
)
|
|
|
993,530
|
|
Intercompany receivables
|
|
|
602,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(602,809
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,326,019
|
|
|
|
355,727
|
|
|
|
45,365
|
|
|
|
29,715
|
|
|
|
(639,281
|
)
|
|
|
1,117,545
|
|
Intangible assets
|
|
|
|
|
|
|
3,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,152
|
|
Goodwill
|
|
|
567,221
|
|
|
|
24,282
|
|
|
|
143,866
|
|
|
|
|
|
|
|
|
|
|
|
735,369
|
|
Noncurrent assets from risk
management activities
|
|
|
|
|
|
|
6,190
|
|
|
|
5
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
6,186
|
|
Deferred charges and other assets
|
|
|
204,617
|
|
|
|
1,315
|
|
|
|
5,301
|
|
|
|
16,906
|
|
|
|
|
|
|
|
228,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,462,301
|
|
|
$
|
396,042
|
|
|
$
|
731,565
|
|
|
$
|
47,917
|
|
|
$
|
(918,278
|
)
|
|
$
|
5,719,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
1,648,098
|
|
|
$
|
139,863
|
|
|
$
|
107,640
|
|
|
$
|
33,640
|
|
|
$
|
(281,143
|
)
|
|
$
|
1,648,098
|
|
Long-term debt
|
|
|
2,176,473
|
|
|
|
|
|
|
|
|
|
|
|
3,889
|
|
|
|
|
|
|
|
2,180,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,824,571
|
|
|
|
139,863
|
|
|
|
107,640
|
|
|
|
37,529
|
|
|
|
(281,143
|
)
|
|
|
3,828,460
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
1,936
|
|
|
|
|
|
|
|
3,186
|
|
Short-term debt
|
|
|
382,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
382,416
|
|
Liabilities from risk management
activities
|
|
|
27,209
|
|
|
|
22,500
|
|
|
|
531
|
|
|
|
|
|
|
|
(19,571
|
)
|
|
|
30,669
|
|
Other current liabilities
|
|
|
473,101
|
|
|
|
183,077
|
|
|
|
61,458
|
|
|
|
|
|
|
|
(14,746
|
)
|
|
|
702,890
|
|
Intercompany payables
|
|
|
|
|
|
|
75,665
|
|
|
|
525,895
|
|
|
|
1,249
|
|
|
|
(602,809
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
883,976
|
|
|
|
281,242
|
|
|
|
587,884
|
|
|
|
3,185
|
|
|
|
(637,126
|
)
|
|
|
1,119,161
|
|
Deferred income taxes
|
|
|
297,821
|
|
|
|
(25,777
|
)
|
|
|
31,927
|
|
|
|
2,201
|
|
|
|
|
|
|
|
306,172
|
|
Noncurrent liabilities from risk
management activities
|
|
|
|
|
|
|
280
|
|
|
|
5
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
276
|
|
Regulatory cost of removal
obligation
|
|
|
261,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
261,376
|
|
Deferred credits and other
liabilities
|
|
|
194,557
|
|
|
|
434
|
|
|
|
4,109
|
|
|
|
5,002
|
|
|
|
|
|
|
|
204,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,462,301
|
|
|
$
|
396,042
|
|
|
$
|
731,565
|
|
|
$
|
47,917
|
|
|
$
|
(918,278
|
)
|
|
$
|
5,719,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
120
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2005
|
|
|
|
|
|
|
Natural
|
|
|
Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
and
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
Marketing
|
|
|
Storage
|
|
|
Nonutility
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
2,926,096
|
|
|
$
|
7,278
|
|
|
$
|
439,574
|
|
|
$
|
1,419
|
|
|
$
|
|
|
|
$
|
3,374,367
|
|
Investment in subsidiaries
|
|
|
231,342
|
|
|
|
(1,896
|
)
|
|
|
|
|
|
|
|
|
|
|
(229,446
|
)
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
10,663
|
|
|
|
28,949
|
|
|
|
|
|
|
|
504
|
|
|
|
|
|
|
|
40,116
|
|
Cash held on deposit in margin
account
|
|
|
4,170
|
|
|
|
76,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80,956
|
|
Assets from risk management
activities
|
|
|
93,310
|
|
|
|
39,528
|
|
|
|
1,739
|
|
|
|
|
|
|
|
(26,664
|
)
|
|
|
107,913
|
|
Other current assets
|
|
|
666,081
|
|
|
|
421,777
|
|
|
|
36,208
|
|
|
|
63,820
|
|
|
|
(152,441
|
)
|
|
|
1,035,445
|
|
Intercompany receivables
|
|
|
505,728
|
|
|
|
|
|
|
|
|
|
|
|
20,133
|
|
|
|
(525,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,279,952
|
|
|
|
567,040
|
|
|
|
37,947
|
|
|
|
84,457
|
|
|
|
(704,966
|
)
|
|
|
1,264,430
|
|
Intangible assets
|
|
|
|
|
|
|
3,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,507
|
|
Goodwill
|
|
|
566,800
|
|
|
|
24,282
|
|
|
|
143,198
|
|
|
|
|
|
|
|
|
|
|
|
734,280
|
|
Noncurrent assets from risk
management activities
|
|
|
|
|
|
|
2,073
|
|
|
|
1,338
|
|
|
|
|
|
|
|
(2,676
|
)
|
|
|
735
|
|
Deferred charges and other assets
|
|
|
249,179
|
|
|
|
1,461
|
|
|
|
5,737
|
|
|
|
19,831
|
|
|
|
|
|
|
|
276,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,253,369
|
|
|
$
|
603,745
|
|
|
$
|
627,794
|
|
|
$
|
105,707
|
|
|
$
|
(937,088
|
)
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity
|
|
$
|
1,602,422
|
|
|
$
|
144,827
|
|
|
$
|
53,426
|
|
|
$
|
33,089
|
|
|
$
|
(231,342
|
)
|
|
$
|
1,602,422
|
|
Long-term debt
|
|
|
2,177,279
|
|
|
|
|
|
|
|
|
|
|
|
5,825
|
|
|
|
|
|
|
|
2,183,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
3,779,701
|
|
|
|
144,827
|
|
|
|
53,426
|
|
|
|
38,914
|
|
|
|
(231,342
|
)
|
|
|
3,785,526
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
1,250
|
|
|
|
|
|
|
|
|
|
|
|
2,014
|
|
|
|
|
|
|
|
3,264
|
|
Short-term debt
|
|
|
144,809
|
|
|
|
60,000
|
|
|
|
|
|
|
|
51,320
|
|
|
|
(111,320
|
)
|
|
|
144,809
|
|
Liabilities from risk management
activities
|
|
|
|
|
|
|
63,936
|
|
|
|
25,038
|
|
|
|
|
|
|
|
(27,054
|
)
|
|
|
61,920
|
|
Other current liabilities
|
|
|
623,300
|
|
|
|
217,777
|
|
|
|
95,557
|
|
|
|
4,963
|
|
|
|
(38,835
|
)
|
|
|
902,762
|
|
Intercompany payables
|
|
|
|
|
|
|
87,968
|
|
|
|
437,893
|
|
|
|
|
|
|
|
(525,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
769,359
|
|
|
|
429,681
|
|
|
|
558,488
|
|
|
|
58,297
|
|
|
|
(703,070
|
)
|
|
|
1,112,755
|
|
Deferred income taxes
|
|
|
268,108
|
|
|
|
12,369
|
|
|
|
9,563
|
|
|
|
2,167
|
|
|
|
|
|
|
|
292,207
|
|
Noncurrent liabilities from risk
management activities
|
|
|
|
|
|
|
16,654
|
|
|
|
1,338
|
|
|
|
|
|
|
|
(2,676
|
)
|
|
|
15,316
|
|
Regulatory cost of removal
obligation
|
|
|
263,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
263,424
|
|
Deferred credits and other
liabilities
|
|
|
172,777
|
|
|
|
214
|
|
|
|
4,979
|
|
|
|
6,329
|
|
|
|
|
|
|
|
184,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,253,369
|
|
|
$
|
603,745
|
|
|
$
|
627,794
|
|
|
$
|
105,707
|
|
|
$
|
(937,088
|
)
|
|
$
|
5,653,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
18.
|
Related
Party Transactions
|
AEM provides a variety of natural gas management services to our
Kentucky, Louisiana and Mid-States divisions including
furnishing natural gas supplies at fixed and market-based prices
and the management of certain of our underground storage
facilities. Additionally, at times, AEM places financial
instruments for our various divisions to partially insulate us
and our customers from gas price volatility.
Atmos Pipeline and Storage, L.L.C. provides asset management
services for certain of our utility storage fields in exchange
for a contractually negotiated demand charge. The Atmos
Pipeline Texas Division, a division of Atmos,
provides natural gas transportation services to our Atmos Energy
Mid-Tex Division.
Atmos Energy Services, L.L.C., provides natural gas management
services for our own utility operations, other than the Mid-Tex
Division. Prior to the second quarter of fiscal 2004, this
entity conducted limited operations. However, beginning in April
2004, AES began providing natural gas supply management services
to our utility operations in a limited number of states. These
services 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 following summarizes our significant affiliate transactions
with AEM, APS and AES.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, unless otherwise indicated)
|
|
|
Gas
purchases(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollars
|
|
$
|
471,844
|
|
|
$
|
227,315
|
|
|
$
|
235,320
|
|
Volumes (Mcf)
|
|
|
52,554
|
|
|
|
31,370
|
|
|
|
42,518
|
|
Average sales price per Mcf
|
|
$
|
8.98
|
|
|
$
|
7.25
|
|
|
$
|
5.53
|
|
Storage contract fees
|
|
$
|
1,792
|
|
|
$
|
1,753
|
|
|
$
|
2,765
|
|
Natural gas management services
|
|
$
|
3,573
|
|
|
$
|
2,986
|
|
|
$
|
682
|
|
|
|
|
(1) |
|
Gas purchases are made in a competitive bidding process, reflect
market prices and exclude demand and other charges. |
JD Woodward was Senior Vice President, Nonutility Operations of
the Company from April 2001 to April 2006. Woodward Marketing
L.L.C., a wholly-owned subsidiary of the Company through
September 30, 2003 and its successor, AEM, leased office
space from one corporation owned by Mr. Woodward. The lease
originated in April 2002 and was terminated in July 2006.
During 2006, 2005 and 2004, our utility division leased office
space and vehicles from our natural gas marketing and other
nonutility segments. Base lease payments were $1.1 million,
$1.0 million and $1.2 million in 2006, 2005 and 2004.
122
ATMOS
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
19.
|
Selected
Quarterly Financial Data (Unaudited)
|
Summarized unaudited quarterly financial data is presented
below. The sum of net income per share by quarter may not equal
the net income per share for the year due to variations in the
weighted average shares outstanding used in computing such
amounts. Our businesses are seasonal due to weather conditions
in our service areas. For further information on its effects on
quarterly results, see the Results of Operations
discussion included in the Managements Discussion
and Analysis of Financial Condition and Results of
Operations section herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
|
December 31
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
|
(In thousands, except per share data)
|
|
|
Fiscal year 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
$
|
1,405,010
|
|
|
$
|
1,447,620
|
|
|
$
|
402,044
|
|
|
$
|
395,917
|
|
Natural gas marketing segment
|
|
|
1,101,845
|
|
|
|
818,629
|
|
|
|
562,447
|
|
|
|
673,603
|
|
Pipeline and storage segment
|
|
|
39,712
|
|
|
|
45,483
|
|
|
|
35,862
|
|
|
|
39,510
|
|
Other nonutility segment
|
|
|
1,492
|
|
|
|
1,595
|
|
|
|
1,413
|
|
|
|
1,398
|
|
Intersegment eliminations
|
|
|
(264,239
|
)
|
|
|
(279,481
|
)
|
|
|
(138,523
|
)
|
|
|
(138,974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,283,820
|
|
|
|
2,033,846
|
|
|
|
863,243
|
|
|
|
971,454
|
|
Gross profit
|
|
|
346,590
|
|
|
|
405,403
|
|
|
|
204,500
|
|
|
|
260,077
|
|
Operating income
|
|
|
149,697
|
|
|
|
180,833
|
|
|
|
4,803
|
|
|
|
47,283
|
|
Net income (loss)
|
|
|
71,027
|
|
|
|
88,796
|
|
|
|
(18,145
|
)
|
|
|
6,059
|
|
Net income (loss) per basic share
|
|
$
|
0.88
|
|
|
$
|
1.10
|
|
|
$
|
(0.22
|
)
|
|
$
|
0.07
|
|
Net income (loss) per diluted share
|
|
$
|
0.88
|
|
|
$
|
1.10
|
|
|
$
|
(0.22
|
)
|
|
$
|
0.07
|
|
Fiscal year 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility segment
|
|
$
|
913,681
|
|
|
$
|
1,235,377
|
|
|
$
|
501,735
|
|
|
$
|
452,347
|
|
Natural gas marketing segment
|
|
|
493,801
|
|
|
|
512,891
|
|
|
|
466,835
|
|
|
|
632,751
|
|
Pipeline and storage segment
|
|
|
43,690
|
|
|
|
45,546
|
|
|
|
33,449
|
|
|
|
30,604
|
|
Other nonutility segment
|
|
|
1,359
|
|
|
|
1,278
|
|
|
|
1,421
|
|
|
|
1,244
|
|
Intersegment eliminations
|
|
|
(83,907
|
)
|
|
|
(110,007
|
)
|
|
|
(96,563
|
)
|
|
|
(115,659
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,368,624
|
|
|
|
1,685,085
|
|
|
|
906,877
|
|
|
|
1,001,287
|
|
Gross profit
|
|
|
322,103
|
|
|
|
375,894
|
|
|
|
221,274
|
|
|
|
198,366
|
|
Operating income
|
|
|
128,674
|
|
|
|
172,181
|
|
|
|
39,468
|
|
|
|
8,332
|
|
Net income (loss)
|
|
|
59,599
|
|
|
|
88,502
|
|
|
|
4,486
|
|
|
|
(16,802
|
)
|
Net income (loss) per basic share
|
|
$
|
0.79
|
|
|
$
|
1.12
|
|
|
$
|
0.06
|
|
|
$
|
(0.21
|
)
|
Net income (loss) per diluted share
|
|
$
|
0.79
|
|
|
$
|
1.11
|
|
|
$
|
0.06
|
|
|
$
|
(0.21
|
)
|
123
|
|
ITEM 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
None.
|
|
ITEM 9A.
|
Controls
and Procedures
|
Managements
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures that are
designed to provide reasonable assurance that information
required to be disclosed by us, including our consolidated
entities, in the reports that we file or submit to the United
States Securities and Exchange Commission under the Securities
and Exchange Act of 1934, as amended (the Act), is
recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange
Commissions rules and forms. Under the supervision and
with the participation of our management, including our
Chairman, President and Chief Executive Officer (Principal
Executive Officer) and our Senior Vice President and Chief
Financial Officer (Principal Financial Officer), we
evaluated the effectiveness of our disclosure controls and
procedures, as such term is defined under
Rule 13a-15(e)
promulgated under the Act. Based on this evaluation, our
Principal Executive Officer and our Principal Financial Officer
concluded that our disclosure controls and procedures were
effective as of September 30, 2006 in ensuring that
information required to be disclosed by us in this annual report
on
Form 10-K
was accumulated and communicated to our management, including
our Principal Executive and Principal Financial Officers, as
appropriate, to allow timely decisions regarding required
disclosure.
Managements
Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term
is defined in Exchange Act
Rule 13a-15(f),
in providing reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted
accounting principles. Under the supervision and with the
participation of our management, including our Principal
Executive Officer and Principal Financial Officer, we evaluated
the effectiveness of our internal control over financial
reporting based on the framework in Internal
Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).
Based on our evaluation under the framework in Internal
Control-Integrated Framework issued by COSO and applicable
Securities and Exchange Commission rules, our management
concluded that our internal control over financial reporting was
effective as of September 30, 2006.
Ernst & Young LLP has issued its report on
managements assessment and on the effectiveness of the
Companys internal control over financial reporting. That
report appears below.
|
|
|
/s/ ROBERT
W. BEST
|
|
/s/ JOHN
P.
REDDY
|
Robert W. Best
|
|
John P. Reddy
|
Chairman, President and Chief
Executive Officer
|
|
Senior Vice President and Chief
Financial Officer
|
|
|
|
November 20, 2006
|
|
|
124
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors
Atmos Energy Corporation
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control over
Financial Reporting, that Atmos Energy Corporation maintained
effective internal control over financial reporting as of
September 30, 2006, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(the COSO criteria). Atmos Energy Corporations management
is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express an opinion on managements assessment and an
opinion on the effectiveness of the companys internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that Atmos Energy
Corporation maintained effective internal control over financial
reporting as of September 30, 2006, is fairly stated, in
all material respects, based on the COSO criteria. Also, in our
opinion, Atmos Energy Corporation maintained, in all material
respects, effective internal control over financial reporting as
of September 30, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Atmos Energy Corporation as of
September 30, 2006 and 2005, and the related consolidated
statements of income, stockholders equity, and cash flows
for each of the three years in the period ended
September 30, 2006 of Atmos Energy Corporation and our
report dated November 20, 2006 expressed an unqualified
opinion thereon.
ERNST & YOUNG LLP
Dallas, Texas
November 20, 2006
125
Changes
in Internal Control over Financial Reporting
We did not make any changes in our internal control over
financial reporting (as defined in
Rule 13a-15(f)
and
15d-15(f)
under the Act) during the fourth quarter of the fiscal year
ended September 30, 2006 that have materially affected, or
are reasonably likely to materially affect, our internal control
over financial reporting.
|
|
ITEM 9B.
|
Other
Information
|
Not applicable.
PART III
|
|
ITEM 10.
|
Directors
and Executive Officers of the Registrant
|
Information regarding directors and compliance with
Section 16(a) of the Securities Exchange Act of 1934 is
incorporated herein by reference from the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 7, 2007. Information regarding
executive officers is included in Part I of this
Form 10-K.
Identification of the members of the Audit Committee of the
Board of Directors as well as the Board of Directors
determination as to whether one or more audit committee
financial experts are serving on the Audit Committee of the
Board of Directors is incorporated herein by reference from the
Companys Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 7, 2007.
The Company has adopted a code of ethics for its principal
executive officer, principal financial officer and principal
accounting officer. Such code of ethics is represented by the
Companys Code of Conduct, which is applicable to all
directors, officers and employees of the Company, including the
Companys principal executive officer, principal financial
officer and principal accounting officer. A copy of the
Companys Code of Conduct is posted on the Companys
website at www.atmosenergy.com under Corporate
Governance. In addition, any amendment to or waiver
granted from a provision of the Companys Code of Conduct
will be posted on the Companys website under
Corporate Governance.
|
|
ITEM 11.
|
Executive
Compensation
|
Incorporated herein by reference from the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 7, 2007.
|
|
ITEM 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Security ownership of certain beneficial owners and of
management is incorporated herein by reference from the
Companys Definitive Proxy Statement for the Annual Meeting
of Shareholders on February 7, 2007. Information concerning
our equity compensation plans is provided in Part II,
Item 5, Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities,
of this Annual Report on
Form 10-K.
|
|
ITEM 13.
|
Certain
Relationships and Related Transactions
|
Incorporated herein by reference from the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 7, 2007.
126
|
|
ITEM 14.
|
Principal
Accountant Fees and Services
|
Incorporated herein by reference from the Companys
Definitive Proxy Statement for the Annual Meeting of
Shareholders on February 7, 2007.
PART IV
|
|
ITEM 15.
|
Exhibits
and Financial Statement Schedules
|
(a) 1. and 2. Financial statements and financial
statement schedules.
The financial statements and financial statement schedule listed
in the Index to Financial Statements in Item 8 are filed as
part of this
Form 10-K.
3. Exhibits
The exhibits listed in the accompanying Exhibits Index are
filed as part of this
Form 10-K.
The exhibits numbered 10.7(a) through 10.16(e) are management
contracts or compensatory plans or arrangements.
127
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
ATMOS ENERGY CORPORATION
(Registrant)
John P. Reddy
Senior Vice President
and Chief Financial Officer
Date: November 22, 2006
128
POWER OF
ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below hereby constitutes and appoints Robert W. Best and
John P. Reddy, or either of them acting alone or together, as
his true and lawful
attorney-in-fact
and agent with full power to act alone, for him and in his name,
place and stead, in any and all capacities, to sign any and all
amendments to this
Form 10-K,
and to file the same, with all exhibits thereto, and all other
documents in connection therewith, with the Securities and
Exchange Commission, granting unto said
attorney-in-fact
and agent full power and authority to do and perform each and
every act and thing requisite and necessary to be done in and
about the premises, as fully to all intents and purposes as he
might or could do in person, hereby ratifying and confirming all
that said
attorney-in-fact
and agent, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
date indicated:
|
|
|
|
|
|
|
/s/ ROBERT
W. BEST
Robert
W. Best
|
|
Chairman, President and Chief
Executive Officer
|
|
November 22, 2006
|
|
|
|
|
|
/s/ JOHN
P. REDDY
John
P. Reddy
|
|
Senior Vice President and Chief
Financial Officer
|
|
November 22, 2006
|
|
|
|
|
|
/s/ F.
E.
MEISENHEIMER
F.
E. Meisenheimer
|
|
Vice President and Controller
(Principal Accounting Officer)
|
|
November 22, 2006
|
|
|
|
|
|
/s/ TRAVIS
W.
BAIN, II
Travis
W. Bain, II
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ DAN
BUSBEE
Dan
Busbee
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ RICHARD
W. CARDIN
Richard
W. Cardin
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ THOMAS
J. GARLAND
Thomas
J. Garland
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ RICHARD
K. GORDON
Richard
K. Gordon
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ GENE
C. KOONCE
Gene
C. Koonce
|
|
Director
|
|
November 22, 2006
|
129
|
|
|
|
|
|
|
/s/ THOMAS
C. MEREDITH
Thomas
C. Meredith
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ PHILLIP
E. NICHOL
Phillip
E. Nichol
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ NANCY
K. QUINN
Nancy
K. Quinn
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ STEPHEN
R. SPRINGER
Stephen
R. Springer
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ CHARLES
K. VAUGHAN
Charles
K. Vaughan
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ RICHARD
WARE II
Richard
Ware II
|
|
Director
|
|
November 22, 2006
|
130
Schedule II
ATMOS
ENERGY CORPORATION
Three
Years Ended September 30, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
Balance at
|
|
Charged to
|
|
Charged to
|
|
|
|
|
|
Balance
|
|
|
Beginning
|
|
Cost &
|
|
Other
|
|
|
|
|
|
at End
|
|
|
of Period
|
|
Expenses
|
|
Accounts
|
|
|
Deductions
|
|
|
of Period
|
|
|
(In thousands)
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
15,613
|
|
$
|
21,819
|
|
$
|
|
|
|
$
|
23,746
|
(2)
|
|
$
|
13,686
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
7,214
|
|
$
|
20,293
|
|
$
|
4,563
|
(1)
|
|
$
|
16,457
|
(2)
|
|
$
|
15,613
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
13,051
|
|
$
|
5,379
|
|
$
|
|
|
|
$
|
11,216
|
(2)
|
|
$
|
7,214
|
|
|
|
(1) |
|
Represents allowance for doubtful accounts recorded in
connection with the TXU Gas acquisition. |
|
(2) |
|
Uncollectible accounts written off. |
131
EXHIBITS INDEX
Item 14.(a)(3)
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
|
|
|
Plan of
Reorganization
|
|
|
|
2
|
.1(a)
|
|
Agreement and Plan of Merger and
Reorganization dated as of September 21, 2001, by and among
Atmos Energy Corporation, Mississippi Valley Gas Company and the
Shareholders Named on the Signature Pages hereto
|
|
Exhibit 2.2 to
Form 10-K
for fiscal year ended September 30, 2001 (File
No. 1-10042)
|
|
2
|
.1(b)
|
|
Agreement and Plan of Merger by
and between TXU Gas Company and LSG Acquisition Corporation
dated June 17, 2004
|
|
Exhibit 2.1 to
Form 8-K
dated June 17, 2004 (File No.
1-10042)
|
|
2
|
.1(c)
|
|
Amendment No. 1 to Merger
Agreement, dated as of September 30, 2004, by and between
LSG Acquisition Corporation and TXU Gas Company LP
|
|
Exhibit 2.1 to
Form 8-K
dated September 30, 2004 (File No. 1-10042)
|
|
|
|
|
Articles of Incorporation and
Bylaws
|
|
|
|
3
|
.1
|
|
Amended and Restated Articles of
Incorporation of Atmos Energy Corporation (as of
February 9, 2005)
|
|
Exhibit 3(I) to
Form 10-Q
dated March 31, 2005 (File No. 1-10042)
|
|
3
|
.2
|
|
Amended and Restated Bylaws of
Atmos Energy Corporation (as of August 13, 2003)
|
|
Exhibit 4.2 to
Form S-3
dated August 31, 2004 (File No.
333-118706)
|
|
|
|
|
Instruments Defining Rights of
Security Holders
|
|
|
|
4
|
.1
|
|
Specimen Common Stock Certificate
(Atmos Energy Corporation)
|
|
Exhibit (4)(b) to
Form 10-K
for fiscal year ended September 30, 1988 (File
No. 1-10042)
|
|
4
|
.2
|
|
Rights Agreement, dated as of
November 12, 1997, between the Company and BankBoston,
N.A., as Rights Agent
|
|
Exhibit 4.1 to
Form 8-K
dated November 12, 1997 (File No. 1-10042)
|
|
4
|
.3
|
|
First Amendment to Rights
Agreement dated as of August 11, 1999, between the Company
and BankBoston, N.A., as Rights Agent
|
|
Exhibit 2 to
Form 8-A,
Amendment No. 1, dated August 12, 1999 (File No.
1-10042)
|
|
4
|
.4
|
|
Second Amendment to Rights
Agreement dated as of February 13, 2002, between the
Company and EquiServe Trust Company, N.A., fka BankBoston, N.A.,
as Rights Agent
|
|
Exhibit 4 to
Form 10-Q
for quarter ended December 31, 2001 (File No. 1-10042)
|
|
4
|
.5
|
|
Registration Rights Agreement,
dated as of December 3, 2002, by and among Atmos Energy
Corporation and the Shareholders of Mississippi Valley Gas
Company
|
|
Exhibit 99.2 to
Form 8-K/A,
dated December 3, 2002 (File No. 1-10042)
|
|
4
|
.6
|
|
Standstill Agreement, dated as of
December 3, 2002, by and among Atmos Energy Corporation and
the Shareholders of Mississippi Valley Gas Company
|
|
Exhibit 99.3 to
Form 8-K/A,
dated December 3, 2002 (File No. 1-10042)
|
|
4
|
.7
|
|
Indenture dated as of
July 15, 1998 between Atmos Energy Corporation and
U.S. Bank Trust National Association, Trustee
|
|
Exhibit 4.8 to
Form S-3
dated August 31, 2004 (File No.
333-118706)
|
|
4
|
.8
|
|
Indenture between Atmos Energy
Corporation, as Issuer, and SunTrust Bank, Trustee dated as of
May 22, 2001
|
|
Exhibit 99.3 to
Form 8-K
dated May 15, 2001 (File No.
1-10042)
|
132
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
4
|
.9(a)
|
|
Indenture of Mortgage, dated as of
July 15, 1959, from United Cities Gas Company to First
Trust of Illinois, National Association, and M.J. Kruger, as
Trustees, as amended and supplemented through December 1,
1992 (the Indenture of Mortgage through the
20th Supplemental Indenture)
|
|
Exhibit to Registration Statement
of United Cities Gas Company on
Form S-3
(File No.
33-56983)
|
|
4
|
.9(b)
|
|
Twenty-First Supplemental
Indenture dated as of February 5, 1997 by and among United
Cities Gas Company and Bank of America Illinois and First
Trust National Association and Russell C. Bergman
supplementing Indenture of Mortgage dated as of July 15,
1959
|
|
Exhibit 10.7(a) to
Form 10-K
for fiscal year ended September 30, 1997 (File
No. 1-10042)
|
|
4
|
.9(c)
|
|
Twenty-Second Supplemental
Indenture dated as of July 29, 1997 by and among Atmos
Energy Corporation and First Trust National Association and
Russell C. Bergman supplementing Indenture of Mortgage dated as
of July 15, 1959
|
|
Exhibit 4.10(c) to
Form S-3
dated August 31, 2004 (File No.
333-118706)
|
|
4
|
.10(a)
|
|
Indenture between United Cities
Gas Company and Bank of America Illinois, as Trustee dated as of
November 15, 1995
|
|
Exhibit 4.11(a) to
Form S-3
dated August 31, 2004 (File No.
333-118706)
|
|
4
|
.10(b)
|
|
First Supplemental Indenture
between Atmos Energy Corporation and Bank of America Illinois,
as Trustee dated as of July 29, 1997
|
|
Exhibit 4.11(b) to
Form S-3
dated August 31, 2004 (File No.
333-118706)
|
|
4
|
.11(a)
|
|
Debenture Certificate for the
63/4%
Debentures due 2028
|
|
Exhibit 99.2 to
Form 8-K
dated July 22, 1998 (File No. 1-10042)
|
|
4
|
.11(b)
|
|
Global Security for the
73/8% Senior
Notes due 2011
|
|
Exhibit 99.2 to
Form 8-K
dated May 15, 2001 (File No. 1-10042)
|
|
4
|
.11(c)
|
|
Global Security for the
51/8% Senior
Notes due 2013
|
|
Exhibit 10(2)(c) to
Form 10-K
for the year ended September 30, 2004 (File
No. 1-10042)
|
|
4
|
.11(d)
|
|
Global Security for the Floating
Rate Senior Notes due 2007
|
|
Exhibit 10(2)(d) to
Form 10-K
for the year ended September 30, 2004 (File
No. 1-10042)
|
|
4
|
.11(e)
|
|
Global Security for the
4.00% Senior Notes due 2009
|
|
Exhibit 10(2)(e) to
Form 10-K
for the year ended September 30, 2004 (File
No. 1-10042)
|
|
4
|
.11(f)
|
|
Global Security for the
4.95% Senior Notes due 2014
|
|
Exhibit 10(2)(f) to
Form 10-K
for the year ended September 30, 2004 (File
No. 1-10042)
|
|
4
|
.11(g)
|
|
Global Security for the
5.95% Senior Notes due 2034
|
|
Exhibit 10(2)(g) to
Form 10-K
for the year ended September 30, 2004 (File
No. 1-10042)
|
|
|
|
|
Material Contracts
|
|
|
|
10
|
.1
|
|
Guaranty of Atmos Energy
Corporation dated June 17, 2004
|
|
Exhibit 10.2 to
Form 8-K
dated June 17, 2004 (File No. 1-10042)
|
|
10
|
.2(a)
|
|
Transitional Services Agreement,
dated as of October 1, 2004, by and between Atmos Energy
Corporation and TXU Gas Company LP
|
|
Exhibit 10.1 to
Form 8-K
dated September 30, 2004 (File No. 1-10042)
|
|
10
|
.2(b)
|
|
Transitional Services Agreement,
dated as of October 1, 2004, by and between Atmos Energy
Corporation, Oncor Utility Solutions (Texas) Company and TXU
Electric Delivery Company
|
|
Exhibit 10.2 to
Form 8-K
dated September 30, 2004 (File No. 1-10042)
|
133
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
10
|
.2(c)
|
|
Transitional Services Agreement,
dated as of October 1, 2004, by and between Atmos Energy
Corporation and TXU Business Services Company (Exhibit A to
Schedule 2 containing listing of employee credit and
procurement cards is omitted, to be supplementally furnished to
the Commission upon request)
|
|
Exhibit 10.3 to
Form 8-K
dated September 30, 2004 (File No. 1-10042)
|
|
10
|
.2(d)
|
|
Transitional Access Agreement,
dated as of October 1, 2004, by and among Atmos Energy
Corporation and TXU Energy Retail Company LP, TXU Business
Services Company, TXU Properties Company and TXU Electric
Delivery Company
|
|
Exhibit 10.4 to
Form 8-K
dated September 30, 2004 (File No. 1-10042)
|
|
10
|
.3
|
|
Revolving Credit Agreement
(3 Year Facility), dated as of October 18, 2005, among
Atmos Energy Corporation, SunTrust Bank, as Administrative
Agent, JPMorgan Chase Bank, N.A., as Syndication Agent and Bank
of America, N.A., Wachovia Bank, National Association and
Societe Generale, as
Co-Documentation
Agents, and the lenders from time to time parties thereto
|
|
Exhibit 10.1 to
Form 8-K
dated October 18, 2005 (File No. 1-10042)
|
|
10
|
.4
|
|
Pipeline Construction and
Operating Agreement, dated November 30, 2005, by and
between Atmos-Pipeline Texas, a division of Atmos Energy
Corporation, a Texas and Virginia corporation and Energy
Transfer Fuel, LP, a Delaware limited partnership
|
|
Exhibit 10.1 to
Form 8-K
dated November 30, 2005 (File No. 1-10042)
|
|
10
|
.5(a)
|
|
Uncommitted Second Amended and
Restated Credit Agreement, dated to be effective March 30,
2005, among Atmos Energy Marketing, LLC, Fortis Capital Corp.,
BNP Paribas and the other financial institutions which may
become parties thereto.
|
|
Exhibit 10.1 to Form 8-K
dated March 30, 2005 (File No. 1-10042)
|
|
10
|
.5(b)
|
|
First Amendment, dated as of
November 28, 2005, to the Uncommitted Second Amended and
Restated Credit Agreement, dated to be effective March 30,
2005, among Atmos Energy Marketing, LLC, Fortis Capital Corp.,
BNP Paribas, Société Générale, and the other
financial institutions which may become parties thereto.
|
|
Exhibit 10.1 to Form 8-K dated
November 28, 2005 (File No. 1-10042)
|
|
10
|
.5(c)
|
|
Second Amendment, dated as of
March 31, 2006, to the Uncommitted Second Amended and
Restated Credit Agreement, dated to be effective March 30,
2005, among Atmos Energy Marketing, LLC, Fortis Capital Corp.,
BNP Paribas, Société Générale and the other
financial institutions which may become parties thereto
|
|
Exhibit 10.1 to
Form 8-K
dated March 31, 2006 (File No. 1-10042)
|
134
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
10
|
.6
|
|
Revolving Credit Agreement (364
Day Facility), dated as of November 7, 2006, among Atmos
Energy Corporation, SunTrust Bank, as Administrative Agent,
Wachovia Bank, N.A., as Syndication Agent and Bank of America,
N.A., JPMorgan Chase Bank, N.A., and the Royal Bank of Scotland,
Plc as Co-Documentation Agents, and the lenders from time to
time parties thereto
|
|
Exhibit 10.1 to
Form 8-K
dated November 7, 2006 (File No. 1-10042)
|
|
|
|
|
Executive Compensation Plans
and Arrangements
|
|
|
|
10
|
.7(a)*
|
|
Form of Atmos Energy Corporation
Change in Control Severance Agreement Tier I
|
|
Exhibit 10.21(b) to
Form 10-K
for fiscal year ended September 30, 1998 (File
No. 1-10042)
|
|
10
|
.7(b)*
|
|
Form of Amendment No. One to
the Atmos Energy Corporation Change in Control Severance
Agreement, Tier I
|
|
Exhibit 10.1 to
Form 8-K
dated May 9, 2006 (File No. 1-10042)
|
|
10
|
.7(c)*
|
|
Form of Atmos Energy Corporation
Change in Control Severance Agreement Tier II
|
|
Exhibit 10.21(c) to
Form 10-K
for fiscal year ended September 30, 1998 (File
No. 1-10042)
|
|
10
|
.7(d)*
|
|
Form of Amendment No. One to
the Atmos Energy Corporation Change in Control Severance
Agreement, Tier II
|
|
Exhibit 10.2 to
Form 8-K
dated May 9, 2006 (File No. 1-10042)
|
|
10
|
.8*
|
|
Atmos Energy Corporation Long-Term
Stock Plan for the United Cities Gas Company Division
|
|
Exhibit 99.1 to
Form S-8
filed July 29, 1997 (File No.
333-32343)
|
|
10
|
.9(a)*
|
|
Atmos Energy Corporation Executive
Retiree Life Plan
|
|
Exhibit 10.31 to
Form 10-K
for fiscal year ended September 30, 1997 (File
No. 1-10042)
|
|
10
|
.9(b)*
|
|
Amendment No. 1 to the Atmos
Energy Corporation Executive Retiree Life Plan
|
|
Exhibit 10.31(a) to
Form 10-K
for fiscal year ended September 30, 1997 (File
No. 1-10042)
|
|
10
|
.10(a)*
|
|
Description of Financial and
Estate Planning Program
|
|
Exhibit 10.25(b) to
Form 10-K
for fiscal year ended September 30, 1997 (File
No. 1-10042)
|
|
10
|
.10(b)*
|
|
Description of Sporting Events
Program
|
|
Exhibit 10.26(c) to
Form 10-K
for fiscal year ended September 30, 1993 (File
No. 1-10042)
|
|
10
|
.11(a)*
|
|
Atmos Energy Corporation
Supplemental Executive Benefits Plan, Amended and Restated in
its Entirety August 12, 1998
|
|
Exhibit 10.26 to
Form 10-K
for fiscal year ended September 30, 1998 (File
No. 1-10042)
|
|
10
|
.11(b)*
|
|
Atmos Energy Corporation
Performance-Based Supplemental Executive Benefits Plan,
Effective Date August 12, 1998
|
|
Exhibit 10.32 to
Form 10-K
for fiscal year ended September 30, 1998 (File
No. 1-10042)
|
|
10
|
.11(c)*
|
|
Amendment No. One to the
Atmos Energy Corporation Performance-Based Supplemental
Executive Benefits Plan, Effective Date January 1, 1999
|
|
Exhibit 10.2 to
Form 10-Q
for quarter ended December 31, 2000 (File No. 1-10042)
|
|
10
|
.11(d)*
|
|
Atmos Energy Corporation
Performance-Based Supplemental Executive Benefits Plan
Trust Agreement, Effective Date December 1, 2000
|
|
Exhibit 10.1 to
Form 10-Q
for quarter ended December 31, 2000 (File No. 1-10042)
|
|
10
|
.11(e)*
|
|
Form of Individual
Trust Agreement for the Supplemental Executive Benefits Plan
|
|
Exhibit 10.3 to
Form 10-Q
for quarter ended December 31, 2000 (File No. 1-10042)
|
|
10
|
.12*
|
|
Atmos Energy Corporation Executive
Nonqualified Deferred Compensation Plan
|
|
Exhibit 10.33 to
Form 10-K
for fiscal year ended September 30, 1998 (File
No. 1-10042)
|
135
|
|
|
|
|
|
|
|
|
|
|
Page Number or
|
Exhibit
|
|
|
|
Incorporation by
|
Number
|
|
Description
|
|
Reference to
|
|
|
10
|
.13(a)*
|
|
Mini-Med/Dental Benefit Extension
Agreement dated October 1, 1994
|
|
Exhibit 10.28(f) to
Form 10-K
for fiscal year ended September 30, 2001 (File
No. 1-10042)
|
|
10
|
.13(b)*
|
|
Amendment No. 1 to
Mini-Med/Dental Benefit Extension Agreement dated
August 14, 2001
|
|
Exhibit 10.28(g) to
Form 10-K
for fiscal year ended September 30, 2001 (File
No. 1-10042)
|
|
10
|
.13(c)*
|
|
Amendment No. 2 to
Mini-Med/Dental Benefit Extension Agreement dated
December 31, 2002
|
|
Exhibit 10.1 to
Form 10-Q
for quarter ended December 31, 2002 (File No. 1-10042)
|
|
10
|
.14*
|
|
Atmos Energy Corporation Equity
Incentive and Deferred Compensation Plan for Non-Employee
Directors
|
|
Exhibit C to Definitive Proxy
Statement on Schedule 14A filed December 30, 1998 (File
No. 1-10042)
|
|
10
|
.15*
|
|
Atmos Energy Corporation Outside
Directors
Stock-for-Fee
Plan (Amended and Restated as of November 12, 1997)
|
|
Exhibit 10.28 to
Form 10-K
for fiscal year ended September 30, 1997 (File
No. 1-10042)
|
|
10
|
.16(a)*
|
|
Atmos Energy Corporation 1998
Long-Term Incentive Plan (as amended and restated
February 14, 2002)
|
|
Exhibit 10.1 to
Form 10-Q
for quarter ended March 31, 2002 (File No. 1-10042)
|
|
10
|
.16(b)*
|
|
Form of Non-Qualified Stock Option
Agreement under the Atmos Energy Corporation 1998 Long-Term
Incentive Plan
|
|
Exhibit 10.16(b) to
Form 10-K
for fiscal year ended September 30, 2005 (File
No. 1-10042)
|
|
10
|
.16(c)*
|
|
Form of Award Agreement of
Restricted Stock With Time-Lapse Vesting under the Atmos Energy
Corporation 1998 Long-Term Incentive Plan
|
|
Exhibit 10.16(c) to
Form 10-K
for fiscal year ended September 30, 2005 (File
No. 1-10042)
|
|
10
|
.16(d)*
|
|
Form of Award Agreement of
Performance-Based Restricted Stock Units under the Atmos Energy
Corporation 1998 Long-Term Incentive Plan
|
|
Exhibit 10.16(d) to
Form 10-K
for fiscal year ended September 30, 2005 (File
No. 1-10042)
|
|
10
|
.16(e)*
|
|
Atmos Energy Corporation Annual
Incentive Plan for Management (as amended and restated
February 14, 2002)
|
|
Exhibit 10.2 to
Form 10-Q
for quarter ended March 31, 2002 (File No. 1-10042)
|
|
12
|
|
|
Statement of computation of ratio
of earnings to fixed charges
|
|
|
|
|
|
|
Other Exhibits, as
indicated
|
|
|
|
21
|
|
|
Subsidiaries of the registrant
|
|
|
|
23
|
|
|
Consent of independent registered
public accounting firm, Ernst & Young LLP
|
|
|
|
24
|
|
|
Power of Attorney
|
|
Signature page of
Form 10-K
for fiscal year ended September 30, 2006
|
|
31
|
|
|
Rule 13a-14(a)/15d-14(a)
Certifications
|
|
|
|
32
|
|
|
Section 1350 Certifications **
|
|
|
|
99
|
|
|
Annual Certification Pursuant to
Section 303A.12 of the New York Stock Exchange Listed
Company Manual
|
|
|
|
|
|
* |
|
This exhibit constitutes a management contract or
compensatory plan, contract, or arrangement. |
|
** |
|
These certifications pursuant to 18 U.S.C.
Section 1350 by the Companys Chief Executive Officer
and Chief Financial Officer, furnished as Exhibit 32 to this
Annual Report on
Form 10-K,
will not be deemed to be filed with the Securities and Exchange
Commission or incorporated by reference into any filing by the
Company under the Securities Act of 1933 or the Securities
Exchange Act of 1934, except to the extent that the Company
specifically incorporates such certifications by reference. |
136